ML20137X344
| ML20137X344 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 03/03/1986 |
| From: | Corbin McNeil Public Service Enterprise Group |
| To: | Adensam E Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8603060109 | |
| Download: ML20137X344 (127) | |
Text
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1 Pubhc Service Electric and Gas Cornpany
?
Corbin A. McNeill, Jr. Public Sennce Electnc and Gas Company P.O. Box 236 Hancocks Bndoe,NJ 08038 609 33^4800 Vice President -
Nuclear March 3, 1986
~
Director of Nuclear Reactor Regulation United States Nuclear Regulatory Commission
-7920 Norfolk Avenue 1
Bethesda, Maryland 20814 Attention: Ms. Elinor Adensam, Director Project Directorate 3 Division of BWR Licensing i
Dear Ms. Adensam:
FINAL SAFETY ANALYSIS REPORT REVISIONS 1
HOPE CREEK GENERATING STATION
, DOCKET NO. 50-354 Public Service Electric and Gas Company (PSE&G) hereby submits various revisions to the Hope Creek Generating Station (HCGS) Final Safety Analysis Report (FSAR). The attached revisions to the HCGS FSAR contain: 1) text changes '
due to the resolution of various Safety Evaluation Report (SER) Outstanding and Confirmatory Items; 2) revisions j to maintain FSAR consistency with the Technical Specifications;
! 3) revisions to reconcile as-built plant discrepancies;
! and 4) general changes to the FSAR text, tables and figures.
1 Attachment 1 provides a brief summary and explanation for
, each change while Attachment 2 contains the actual marked-up 1
sections of the FSAR. These revisions will be incorporated in FSAR Amendment 15 after fuel load but are being filed
, now in order to accurately reflect the design and operation of HCGS and support the issuance of an operating license.
In addition, an affidavit is provided to affirm that the j
matters set forth in this transmittal are true and accurate.
Should you have any questions on the subject filing, do not hesitate to contact us.
Sincerely,
- W1 % ,
\
k A
i
Director of Nuclear 2 3-3-86 Reactor Regulation Affidavit Attachments (2)
C D.H. Wagner USNRC Licensing Project Manager R.W. Borchardt USNRC Senior Resident Inspector ,
3 O
UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION DOCKET NO. 50-354
- PUBLIC SERVICE ELECTRIC AND GAS COMPANY FINAL SAFETY ANALYSIS REPORT REVISIONS Public Service Electric and Gas Company (PSE&G) hereby submits various revisions to the Hope Creek Generating
- Station (HCGS) Final Safety Analysis Report (FSAR). These e HCGS FSAR revisions consists of text changes due to resolution of various Safety Evaluation Report (SER) Outstanding and
. Confirmatory Issues, revisions to maintain FSAR consistency with the Technical Specifications, revisions to reconcile as-built plant discrepancies, and general revisions to the FSAR text, tables and figures.
F The matters set forth in these revisions are true and accurate to the best of my knowledge, information, and belief.
Respectfully submitted, Public Service Electric i and Gas Company
$b By: __
Corbin A. McNe Q Vice President - Nuclear Sworn to and' subscribed before me, a Notary Public of New'Jers'cy,'this s & 2, day of March 1986.
d M c DELORisD.HA00EN A Notary Pubk of New Jertov My hemmen hpms Mpe ld,1MO ;
ATTACHMENT 1
SUMMARY
OF CHANGES, ADDITIONS AND/OR MODIFICATIONS 1.2.4.6.9 Editorial revision 1.8.1.52
- Revisions provide a position statement 1.8.1.140 for Regulatory Guide (RG) 1.52 Position C.2.1 and RG 1.140 Position C.2.f which indicates Table 4-3 of ANSI N509-1980 is used as the acceptance criteria for maximum allowable leakage in ductwork.
This ANSI standard gives three calculational methods but indicates the lowest should be utilized; hence, the necessity for the HCGS position statement. This revision affects SER Section 9.4.1 (pg. 9-28) since a statement indicates RG 1.52 and 1.140 are met, which is true, but as clarified via this change.
1.8.1.118 + Revisions reflect commitments contained Q421.22 in the PSE&G to NRC letter dated February 24, 1986 regarding the use of lifted leads and jumpers for certain at power surveillance tests.
1.8.1.140 + Revisions reflect commitments made 14.2.12.1.17 in the letter from PSE&G to the NRC 14.2.12.1.19 on January 31, 1986 regarding the Initial 14.2.12.1.23 Test Program Request for Additional 14.2.12.1.25 Information dated February 14, 1986.
14.2.12.1.46 14.2.12.1.61 14.2.12.1.63 14.2.12.1.68 14.2.12.1.69 l.10.2.II.B.3 Revision reflects statement made in SER Section 9.3.2 which requires a demonstration of the capability of the post-accident sampling system to obtain and analyze a reactor coolant sample.
1.10.2.II.K.3.16 Revision reflects as-built plant conditions.
1.14.1.31.2 Revision indicates that the EOPs address specific actions to mitigate ATWS events and provides a cross-reference to the PGP and P-STG.
2 :
T3.2-1 Revision necessary to maintain cunsistency Pg. 1 of 41 with FSAR Table 3.9-5cc.
4 T3.2-1 Revisions indicate that the TIP shear
-Pg. 26,41_of 41 valve assemblies and probe tubing are
, non-ASME.
l T3.2-1 Revision deletes the reference to the l Pg. 30 of 41 SLC system accumulators in support F9.3-8 of the N-5 packages.
3.9.3.1.12 Revisions provide the actual nozzle 3.9.3.1.16 loads and update current allowable
- T3.9-5d,n,q,s,t,v values. These revisions provide the Q210.2 PSE&G response to IDVP OR-25.
T3.ll-3 Revision indicates that the harsh environ--
j mental qualification has been complete.
l T3.11-6 Revision necessary to meet commitments contain in FSAR Section 8.1.4.14 and IEEE 384-1981.
i 6.2.4.3.2.18 Revision reflects the as-built plant
! conditions and maintains consistency j with FSAR Section 6.2.5.2.5.
6.2.5.3.3 Revisions add a reference for the copper i T6.2-21 corrosion rate, which along with aluminum,
] are negligible and hence not included j in the hydrogen generation calculation.
i T6.2-14 Revisions are necessary to indicate F6.3-23 that the three blowout panels listed in the table are in affect one panel 4 extending from elevation 136'-0" to 151'-6". Hence, a revision has been j' made to reflect elevations 132'/145' and show one blowout panel and therefore the blowout panel shown on elevation
, 162 of the figure is deleted.
t 7.6.1.2.2 Revision correctly addresses details contained in operational procedure OP-IS.BC-101-104(Q). This revision
- impacts SER Supplement 4, Section 7.6.2.1
- since the surveillance of the RHR injection valves will be performed only during j cold shutdown.
- 7.7.1.1.2.2 Revision provides a clarification of neutron monitoring equipment in the rod block circuitry.
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';. 9.1.2.2.2.l' Revision to reflec't the as-built plant
' design.
9.1.5.2.2 Revisions reflect the as ~ouilt' design 9.1.5.3.2.2 of the overhead heavy' load handling 9.1.5.3.2.4 system.
9.1.5.3.2.6 9.1.5.3.2.8 j 9.1.5.3.2.9 l 9.1.5.3.2.10 9.1.5.3.3 '
9.1-10-14,22,23 9.3.5 Revision clarifies actual relief valve setpoints for the SLC pump discharge lines.
9.3.5.4 Revisions necessary to maintain consistency 13.4.1.3 with the Technical Specifications.
10.2.4.c
- Revision reflects Item 45 of the PSE&G j
i letter to the NRC dated January 24, 1986 and impacts SER Section 3.5.1.3.2,
! Page 3-16, Item 2 as observations are l not made by watching the valve motion but rather the valve position indicator.
I T13.1-la Revisions update the status of the Manager - Personnel and Administration and provide the resume of the Manager -
Project Installation.
j T13.1-4 Revision provides the resume of the Senior Nuclear Maintenance Supervisor I&C.
i +
13L
- Revisions reflect the information contained
+ in the PSE&G letter to the NRC dated December 30, 1985. These revisions
! provide the response to SER Outstanding '
l Issue #14.
i i 14.2.12.1.43 Revision deletes reference to the operability j
of the CRD system as a prerequisite to reflect a change in the General Electric test specification.
! 14.2.12.1.68 Revision to Acceptance Criteria 6 is 4
necessary to maintain consistency with FSAR Section 9.4.2;1.e.
}
l 14.2.3.12 # Revisions reflect various power ascension i 14.2.3.13 test program modifications approved 14.2.3.14 by the NRC in a-letter to PSE&G dated 14.2.3.27 January 22,-1986.
F14.2-5 I
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4 14.2.12.3.15 Revisions include documentation of 14.2.12.3.39 changes to maintain consistency and reflect acceptable BOP pipe expansion tests conducted at the Limerick facility.
Q430.125 Revision necessary to correct editorial Q430.131 inconsistency with the Colt-Fairbanks Morse Operation & Maintenance Manual.
Q430.131 Revision deletes the reference to a Q430.135 Technical Specification for lube oil storage as such a requirement is not addressed in the Standard Technical Specifications (NUREG-0123).
Q440.7 Revision specifies SRV surveillance test pressure in accordance with General Electric and Target Rock recommendations.
Q480.14 Revision necessary to maintain consistency with FSAR Section 6.2.3.2.3'and to properly reflect.various ISI testing procedures.
Q480.34 Revision deletes the reference to various notes in Table 6.2-24 which were deleted in previous amendments. This revision is editorial in nature as these deletions were overlooked during updates of Table 6.2-24.
- These revisions impact the SER as noted
+ These revisions have previously been submitted to the NRC by PSE&G in a letter as noted.
- These revisions have already been accepted by the NRC in a letter to PSE&G as noted.
1.2.4.6.8 Plant Chilled Water System '
The plant CWS is designed to provide a means of cooling both the fresh air supply an air recirculation to building HVAC systems.
1.2.4.6.9 Process Sampling System i
3 The process sampling system furnishes process information that is required to monitor plant and equipment performance and changes ,
, in operating parameters. Representative liquid and gas samples are taken automatically and/or manually during normal plant
- operation for laboratory or online analyses.
RGWssENTAT10Gl A post-accident sampling system is provided to obtain"b;ccifi;LJL-l samples of the reactor coolant and the suppression pool water in
! accordance with the Regulatory Guide 1.97 requirements. The system has the capability to sample the primary containment J
i atmosphere, thereactorbuildingatmosp(ere,andthetorus atmosphere. g l
$ 1.2.4.6.10 Plant Equipment and Floor Drainage I
The plant equipment and floor drainage systems include both i radioactive and nonradioactive drains. Radioactive drains i contain potentially radioactive materials and are pumped to the radwaste system for cleanup, reuse, or disposal. Nonradioactive
) drain materials are treated to remove oil prior to discharge to i the Delaware River.
1 1.2.4.6.11 Service and Instrument Air Systems,
] The service air system supplies filtered, oil-free, compressed 4 air for plant operation and services.
1 i
) The instrument air. system supplies filtered, dried, and oil-free j compressed air for air-operated instruments.
J
]
i The breathing air system supplies filtered, dried, oil-free, and
! purified compressed air for operating and maintenance personnel j J', working in hazardous areas.
\
1.2-39 Amendment 14 5
HCGS FSAR 11/85 differential pressure indication across each filter component is provided. On the CREF units the pertinent pressure drop is the pressure drop across the upstream HEPA filters. This is instrumented to indicate and activate an alarm in the control room and is available in the plant computer. In addition to this, local differential pressure indication across each filter component is provided. CREF and FRVS compliance with minimum instrumentation requirements is provided in Tables 6.5-4 and 6.8-5, respectively.
- c. Postion C.2.j. of Regulatory Guide ).52 - Overall design considerations include reduction of radiation exposures'during routine maintenance and testing. It is not anticipated, however, that workers will handle filter units immediately after a DBA. Accordingly, no efforts are made to provide a unitized atmosphere cleanup train design specifically to facilitate post-accident removal.
l W9mTj =-
Position C.3.o of the Regulatory Guide 1.52 - Unusual e [. air flow straightening devices are not installed.
Adequate flow distribution is achieved in a low air (
velocity housing without special devices. (
f g.
y The' guidance on spacing between components is not followed for HCGS. Spacing between components may be less than 3 feet where anticipated maintenance does not require this clearance.
g7f Regulatory Guide 1.52 references ANSI'N510-1975. HCGS testing commitments will follow the ANSI N510-1980 issue.
1.8.1.53 Conformance to Reculatory Guide 1.53, Revision 0, June 1973: Application of the Single-Failure Criterion to Nuclear Power Plant Protection Systems HCGS complies with IEEE 379-1972, as endorsed and modified by Regulatory Guide 1.53.
See Section 8.1.4.10 for further discussion of compliance with Regulatory Guide 1.53 and Section 1.8.2 for the NSSS assessment of this Regulatory Guide.
1.8-32 Amendment 13
- - - ~ . - .
INSERT FOR PAGE 1.8-32
- d. Position C.2.1 of Regulatory Guide 1.52 - Table 4-3 of ANSI NS09-1980 Section 4.12 was used as the acceptance criteria for maximum allowable leakage in ductwork.
e 0
l 1
HCGS FSAR 8/84 same as " construction site" (or station site during operation).
When applied to documents, these may be at the central office or work area document control station. The term " installation area" is interpreted to mean the immediate proximity of the location where work is to be performed.
Section 3.5(e), Site Conditions, ANSI N45.2.8-1975, is applied only.if subsequent correction of adjacent nonconformances would damage the item being installed.
Contrary to Section 4.6, Care of Item, ANSI N45.2.8-1975, the constructor or construction manager (or licensee during operation) is assumed to be the " responsible organization" for temporary usage of equipment or facilities, unless specifically prohibited by contract or in writing from the owner. All other conditions and considerations for temporary use in Section 4.6 are applied.
See Chapter 17 for further discussion of quality assurance and Section 1.8.2 for the NSSS assessment of this Regulatory Guide.
1.8.1.117 Conformance to Regulatory Guide 1.117, Revision 1, (
April 1978: Tornado Desion Classification Although Regulatory Guide 1.117 is not applicable to HCGS, per its implementation section, HCGS complies with it.
For further discussion of tornado loadings, see Section 3.3.2.
1.8.1.118 Conformance to Reculatory Guide 1.118, Revision 2, June 1978: Period Testina of Electric Power and Protection Systems IW -
5 Al umoy;. acvulatory cuide 1.11e i: n t :ppliceb!: t: MCCS, p::
4t: imp 10:ent: tier recti n,- HCCS crep!!:: eith it. jt_,
0: Occti n ' .S.2 fer the MSSS ::::::::nt of thic R:;;1:tery C idc.
1.8-100 Amendment 7
+e - -m . <m A
- h. 9
INSERT TO PAGE 1.8-100 Regulatory Guide 1.118 is not applicable to HCGS per its -
implementation section. However, with certain exceptions related to the use of temporary alterations during the performance of required at powered surveillance tests, HCGS is in compliance with this Regulatory Guide.
e k
f HCGS FSAR 11/85 filter plenum since the tank vent has only 1000 cfm per filter plenum.
=
INSERT i Reculatory Guide 1.140 references ANSI N510-1975. HCGS will lUSC' dellow-Athe ANSI N510-1980 issue.
) For further discussion of the atmosphere cleanup systems, see Section 9.4.
1.8.1.141 Conformance to Regulatory Guide 1.141, Revision 0, April 1978: Containment Isolation Provisions for Fluid Systems Although Regulatory Guide 1.141 is not applicable to HCGS, per its implementation section, HCGS complies with the requirements of ANSI N271-1976 (ANS-56.2) as modified and interpreted by Regulatory Guide 1.141, with the exceptions and clarifications discussed below:
ANSI Section 3.1, General, references an American National r Standard and a draft standard for guidance on the development of
,- quality group classifications. The criteria for quality gtoup classifications at the HCGS is based on the guidelines of Regulatory Guide 1.26.
When it is not practical to provide one isolation valve inside and one outside containment, and both valves are located outside primary containment, Section 3.6.4 requires that the valve nearest primary containment be enclosed in a protective leak-tight er controlled-leakage housing to prevent leakage to the atmosphere. Similarly, when greater safety is achieved by the use of a single isolation valve, Section 3.6.5 requires that the isolation valve be enclosed in a protective housing. In the HCGS design, no protective housing is provided. Nonetheless, the design is adequate in that any leakage will be collected within the reactor building, prior to filtration, dilution, and final release to thp environment. Also, extensive leakage will trip sump level alarms, which will alert the main control room operators.
Appendix A depicts typical isolation valve arrangements for BWRs.
The arrangements are applicable to Mark III containment designs and do not apply to HCGS.
For further discussion of containment isolation, see
( Section 6.2.4. ANSI Section 3.6.2, Instrument Lines, states that NRC Regulatory Guide 1.11 provides suitable bases for 1.8-113 Amendment 13 1
INSERT FOR PAGE 1.8-113 Position C.2.f of Regulatory Guide 1.140 - Table 4-3 of ANSI N509-1980 Section 4.12 was used as the acceptance criteria for maximum allowable leakage in ductwork.
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4 HCGS FSAR 1/85 l (12) Applicants should provide a description of the implementation of the position and clarificatior. including pipe and instrumentation drawings, together with either (a) a summary description of procedures for sample collection, sample transfer or transport, and sample analysis, or (b) copies of procedures for sample collection, sample transfer or transport, and sample analysis, in accordance with the proposed review schedule but in no case less than 4 months prior to the issuance of an operating license. A postimplementation review will be performed.
Response
i Provisions for post-accident sampling of reactor coolant and containment atmosphere are described in Section 9.3.2. l The HCGS design incorporates a radioactive gas and liquid sampling system designed by General Electric. Additionally, the radioloaical spectrum and chemical analysis capabilities will be
- reviewed prior tvi'" ' '- to ensure that the appropriate J
analysescanbeperformedfithinthetimesspecifiedin NUREG-0737.
Shielding requirements and source terms used are consistent with -
those used for the Design Review of Plant Shielding, discussed under item II.B.2. The review to assure compliance of the radioactive gas and liquid sampling system for shielding and source term requirements has been completed and is described in i Section 9.3.2.
SYswxaR cwvAT&
- , W3n3YMA II.B.4 TRAINING FOR MITIGATING CORE DAMAGE Position .
We require that the applicant develop a program to ensure that all operating personnel are trained in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged. They must then implement the training program.
Clarification STA and operating personnel from the plant manager through the operations chain to the licensed operators shall receive this training. The training program shall include the following topics: k-T 1.10-36 Amendment 9
and an external air-diaphragm-actuated pilot for the relief function.
The operating history of the safety / relief valves has been poor.
A new design is used in some plants, but the operational history
. is too brief to evaluate the effectiveness of the new design.
l Another way of improving the performance of the valves is to reduce the number of challenges to the valves. This may be done by the methods described above or by other means. The feasibility and contraindications of reducing the number of '
challenges to the valves by the various methods should be studied. Those changes which are shown to decrease the number of challenges without compromising the performance of the valves or other systems should be implemented.
Results of the evaluation shall be submitted by April 1, 1981 for staff review. Documentation of the staff approved modification will be provided by January 1, 1982. The actual modification will be accomplished during the next scheduled refueling outage after January 1, 1982 (if required). e
( Response The NRC staff safety evaluation of the BWR Owners' Group response to NUREG-0737 Item II.K.3.16 states that the following modifications are acceptable methods of reducing SRV challenges and failures: ,
(1) Providing a low-low set (LLS) relief logic system or developing procedures for Equivalent Manual Actions, (2) Lowering.the reactor pressure vessel water level isolation setpoint for main steam isolation valve (MSIV) closure from level 2 to level 1, (3) Increasing the SRV simmer margin, and l (4) Instituting a preventive maintenance program. l uAs BKno of HCGSI provided a low-low set relief logic system /(~ We inter. If' t: incorp;r=tn the BWROG's Generic design.:rt:n :: :::::: 7
, ,_. change. ThesetpointphasbeenchangedfromanRPVLevel2to
( Level 1 as indicated in Figure 5.1-4. No changes will be made to
.t'. the SRV simmer margin. The simmer margin is the difference 1.10-77 Amendment 2 4
i
~ . _ _ _ - _ _ . _ _ - _ _ _ . _ _-a_..
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HCGS FSAR 8/83 by changing rod scram switches to the scram position, tripping the feeder breakers on the reactor protection system power distribution buses, opening the scram discharge volume drain valve, prompt actuation of the standby liquid control (SLC) system, and prompt placement of the RHR in the suppression pool cooling mode to reduce the severity of the containment conditions, 1.14.1.31.2 Response ,
The following actions will be implemented at HCGS in order to
HCGS is implementing Alternate 3A of NUREG-0460, with manual
. initiation of the SLC system. Emergency procedures will be developed for ATWS events. These procedures will address the i
following:
4
- a. SyTptoms
(
- b. Automatic actions
- c. Immediate actions ,
3
- d. Subsequent actions i
- e. Final conditions Operators will be trained to perform the procer actions for ATWS events as part of the formal operator training program.
- llNSEv'r j =
These procedurec will-be ccmplet i -A shirt-A prior to the fuc1 10 d d:tc. -
1 1.14.1.32 ODYN Transient Analysis Code, LRG I/RSB-23
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1.14-26 Amendment 1
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INSERT FOR PAGE 1.14-26 Emergency operating procedures have been developed from the BWR Owner's Group Emergency Procedure Guidelines (EPGs)
Rev. 3. Although these procedures are symptomatic in nature, specific actions are provided to mitigate ATWS events.
The development of these procedures is described in the PGP and P-STG which have been submitted for NRC review (see Appendix 13L).
_____...-__-_...__.___-._-.__._.__m _ _ _ . _ _ . _ . ___...._..__m . _ . . _ _ _ _ _ _ _ _ . _ _ ~ . -
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TABLE 3. 2-1 Page 1 of 41 l HCGS CLASSIFICATION OF STRUCTURES, SYSTEMS, AND COMPONENTS Principal Quality construc-Source Group tion QA TSAR of Loca- Classi- Codes and Seismic Require-Section Supply tion fication Stardards Category ments comments taa ta) (s3 top to tra Princisal Cossonentstern I. Etactor Avstep 4.1
- c. Reactor vessel and head GE A A III-At*3 I Y (*8
- b. Reactor vessel support skirt GE A NA III-At*3 I Y (*)
- c. Reactor vessel appurtenances, GE A A III-At'8 I Y treasure retaining portions --(
- e. Deactor internal structures, GE A NA None I Y <saa engineered safety features
- h. Ccntrol rod drives GE A NA III-At'8 I Y
- 1. Power range detector hardware I Y
- k. Tuel assemblies GE A NA None I Y
- 1. Reactor vessel stabilizer GE A NA III-NF I Y II. Nuclear Bciler Systes 5.1 .
- c. Vessels, level instrumentation GE A A III-1 I Y condensing chamhers
- t. vessels, air accumulators P A,C C III-3 I Y
- c. Air supcly check valver acd P A,C C III-3 I Y l sicing downstream of air succly check valves ,
- d. Picing, safety relief P A C III-3 I Y valve discharge
- o. Picing. sain steam, within GE/P AC A III-1 I Y cutkoard isclation valves
- f. Picing, feedwater, within P A,C A III-1 I Y cutboard inclation valves t888
- o. Picing, pain steam, between P C B III-2 I Y cutboard and outermost inclation valves Picing, feeJoater, between P C B III-2 -I Y t*88 b.
cetkoard and outermost ..
1 sciatica valves Amendment 9 l i
. , - . . . - , - . - , , , . - - - - . , - , . - - , , - . - - - - - . , - . - . , . , , - - , - - , , , . . - - - - , , - - . - - - - , , . . . --, ,~
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ECGS FSAR 1/85 l TABLE 3.2-1 (cont) Page 26 of at l Principal quality Cor.strue-Source Group tion OA FSAR of Loca- Classi- Codes med Seismic Pequire-Sectiss supply tien fication star.darAs Category ments comments ts: tea ass ces ces tre Princisa1 Coescnentoesy3
- c. Centrcle and instrumentation 7.6 associated with other systems recwired fcr safety:
- 1. Process radiation monitoring GE/P A B.C,R,T NA IEEE-279 I Y < 88 3 syrter
- 2. Leak detection system (FCIC, GE/P C NA IEEE-279 I Y t ** s RbCU, NPCI)
( s. High gressere-tow pressure GE C NA IEEE-279 I Y avetes interlocks
- 5. teestaca monitoring system p- _ 1I Y al N TIP probe and purge, GE A,C B III-2 I _Y centatament penetration l kl valves, isolation, TIP pegggE A,C B III-2 I Y l c) Electrical modules, I M GE C NA IEEE-279/323 I Y j and APM 48 ? 3 di Cable. IM and APM, P A,C NA IEEE-279/323 NA Y t**>
(gr '
6.
- with asfety function EEiMBundant reactivity contral GE C MA IEEE-279 I Y avetet ($3CS) i 7. noin stema SEV-relief function GE A,B,C NA IEEE-279 I Y
- 4. Satety system /nonsafety system P A,B,C NA IEEE-279 I Y
{ isolatica r
i
' f. Controls & instrumentation 7.7 associated with systema not reesired fer safety:
- 1. Peacter senaal control system GE A,C NA leone NA N
- 2. Decirewlation flow control GE T NA Mone NA N
/ sYstet 1 3. Nee @ mater control system GE/P T NA Mone NA N
- s. sefseling interlocks GE C NA leone NA N
- 5. Deleted
- 6. Deleted l 7. Pressere regolator & P T NA None NA N tutkine-gerderator system Amendment 9 I L__
INSERT FOR TABLE 3.2-1, PAGE 26 of 41 e) Valve, TIP probe, isolation GE C NA (44) I Y (64) f) Tubing, TIP probe, instrument GE C NA (44) I Y (64) penetration g) Tubing, TIP purge, containment P A,C B III-2 I Y penetration l
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HCGS FSAR 1/86 l T4BLE 1.2-1 (co-t) Page 41 og 41 heater 1s are escluied from the 'F' prngras daring t he detien an$ cor struction g>hase but will be incleie3 in the Q4 Program for* fire protect ies dar ing the operatiers phase.
- * *
- vs water / glycol side of the containwr:t instrument gas tf.*rno-siphon is non-codM.
- The cvI installe5 ;crtion of the as ani cooling witn piping system on the containment ;
instraneat gas cenpessor skids, which is Jesigt.el and teoricated in accordance with l Section I!! of tre ASME code, is not stawped as as installed ruclear piping eystem ard is rot l cewared in a +5 cole Oata pac! cage. l g
_ [h) T,(:7P Wesa esWM'er TeJe%Tc*J 4' D CWMJ WGC MF D 'LT To @S SP D RDS W SQ - Sh% 3CTfLLfC F1HSTCb).
?
s Amendv nt 14 1
I t
- a. The operating conditions for each SLC pump and motor are functionally tested by pumping demineralized water
, through a closed test loop. Each SLC pump is capable j of injecting the net contents of the SLC tank into the reactor in not less than 50 minutes and not more than 125 minutes. Each pump is capable of injecting flow into the reactor against a pressure of zero psig up to
- the initial setpoint pressure of the reactor safety / relief valves (SRVs).
- b. The design conditions for each SLC pump include: l l
- 1. Flow rate: 43 gpm
- 2. Available NPSH, maximum: 12.9 psi
- 3. Maximum operating discharge pressure: 1190 psig l
- 4. Ambient conditions:
Temperature 60 to 101oF Relative humidity: 20 to 90%
- 5. The normal plus upset conditions which control the
! pump design include:
1 l (a) Design pressure 1400 psig l (b) Design temperature 1500F j (c) OBE 2/3 of SSE
- ""-t4en-nese4e-10 d F, '70 pound ,
3 M o - ??O-f00t p und:
i -( c) Disch:rge no= ele-40:d F o = 370 p0:nd:,
) M- $?C-foot pound:
Wr4H- -
4 l
-Fo and %--are a def4 ned-i n-Table-3r9--Sm 1
s.
! 3.9-66
<(
t ,
1 i
The stress limit for the pressure boundary is the ASME B&PV Code allowable stress, 1.0 S for general l membrane. .
I 6. The faulted or emergency conditions include:
(a) Design pressure 1400 psig -
! (b) Design temperature 1500F (c) SSE Horizontal - 1.5 g j
vertical - 0.14 g *
- ld' Outti;n ;;; 10 10 d
- F, - 920 ? : ft, k i., .-___,. ., _2- $$$???$25 us V
.- .> . . -u .- . .-
b.*~7.;_.7_...._,'
s , - __
1 _
i i
k The stress limits for the pressure boundary are 4
120% of ASME B&PV Code allowable-stresses, 1.2 S for general membrane, and 1.8 5 for bending plus :
j a
local membrane. ;
!( -
A cummary of the design calculations and nozzle loads for the SLC i
l l pump components is contained in Table 3.9-5n.
l !
J Main Steam Isolation and Safety / Relief Valves j 3.9.3.1.13 !
i N
l Load combination analytical methods, calculated stresses, and l
allowable limits are shown for the SRVs and the MSIVs in i Tables 3.9-51 and 3.9-5j, respectively.
1 3.9.3.1.14 Safety / Relief Valve Discharge Piping I. t i See Section 3.9.3.1.20.
i .
- 3.9.3.1.15 High Pressure Coolant Injection Turbine l i Although not under the jurisdiction of the ASME B&PV Code,
- Section III, the HPCI turbine is designed and fabricated ;
- Section III, Class 2 component.
]
4 i *
- 3.9-67 i
- Low speed: 710 feet \
- 3. Constant flow rate - 5600 gpm- l
- 4. Normal ambient operating temperature - 60 to 1070F
[ 5. The normal plus upset conditions that control the pump design include:
t (a) Design pressure 1500 psig (b) Design temperature 40 to 1400F (c) OBE 2/3 of SSE (d) Suction nozzle. loads Fo = 5570 pounds, Mo = 15,370 foot-pounds (e) Discharge nozzle loads Fo = 7850' pounds, Mo = "5,;;Xofoot-pounds
/4
] where: 6'#
Fo and Ma ar'e as defined in Table 3.9-5v. .'~ '
]
, \
The stress limits for the pressure boundary are
. . the ASME B&PV Code allowable stresses, 1.0 S for
- general membrane, and 1.5 S for bending plus local
- membrane.
I 6. The faulted or emergency conditions include:
! (a) Design pressure 1500 psig (b) Design temperature 40 to 1400F (c)
~
SSE Horizontal - 1.50 g Vertical - 0.14 g '
Fo = 6680 pounds, (d) Guction nozzle loads -
Mo = 18,450 foot-pounds (e) Discharge nozzle loads Fo = 9420 pounds, l Mo = 18,465 foot-pounds '
where f Fo and Ho are as defined in Table 3.9-5v.
3.9-70 Amendment 1 i
1 L._______________.__________________.___.__________.__________
t s HCGS FSAR TABLE 3.9-5d (cont) Paon 2 of 4 Allowable Actual criteria Loading Component Norrle_Loadgeea Nozzle L341st88 Nortle loads The maximum forces and moments Design basis loads consisting Nozzle N1 Fo = 3760 lb F= N74 S l due to pipe reactions shall not of: (tube inlet) Mo = 15,100 in.-lb M a t4c g ap q
! exceed the allom ble limits 1. D sign pressure i 2. Design temperature Nozzle N2 Fo = 3760 lb F = 198 (6 l 3. Dead weight (tube outlet) Mo = 15,100 in.-1b H = (qqq sn.g .
- - 4. %ermal expansion
. 5. Seismic (Class II basis) Nottle N3 Fo = 3760 lb F 56 tB (shell inlet) Mo = 15,100 in.-Ib M: 18"8 W-LB '
Nozzle N4 Fo = 3760 lb Mo.= 15,100 in.-lb F= %M ts (shell outlet) hugg3g g.g i
i l
1 i
I ,
l ,
l 1
)
8 TABLE 3.9-5d (cont) Page 4 of 4 Allowable Actual criteria Los11ng Component Nozzle Ioads(18 Nozzle Inadat a s Mozzle loads M
The maximum forces and 1. Design pressure Nozzle N1 re = 654 lb W )~z lg g moments due to pipe 2. Design temperature (tube inlet) M. = 2620 in.-Ib g, g, reactions shall not 3. Dead weight exceed the allowable limits 4 Thermal expansion Pfozzle N2 re = 654 lb p=2 g (3
- 5. Seismic (Class II basis) (tube outlet) Me = 2620 in.-lb H
- 4;;L% oJ.t3 Nozzle N3 ro = 654 lb F = DES LB (shell inlet) Me = 3920 in.-lb t1 : 4;;t% gj.$
Nozzle N4 r = 654 lb F= 1% tE, (shell outlet) M. = 3920 in.-lb H g 4.Q cs rg = Allowable resultant nozzle force, Ib. l
= Actual orthogonal nozzle forces in x, y, ar.d z directions.
T, , ry , F, l y r, * + rys
- r,* must be equal to or less than F0
- I M0 = Allowable resultant nozzle moment, in.-lb. l Mx, My, Mg = Actual orthogonal nMzle moments in x, y, and z directions.
l VM,a e nya , ga must be equal to or less than M 0' tang .- 7717 :: l g
f > l I
CSLitu;TED trt126 lm EVALLLAT60 m AccwneD BY GENERAL C-u=CrRAC TEE CETTGR. C-C-@-M nm=p daway 3t ,l%.
Amendment 14 l
,-~. .-
HCGS FSAR 1/86 l TABLE 3.9-5n Page 1 ot 3 l STANDBf LIQUID CONTPOL PUMP
,,,Q' - Limiian, Alic ;ta:
ete*ee, Hententeced-steeee, _k
- c. it e.1;/:,ca '.h' ' ' c~. ;- - - - -A ___m ;c;; r, r- .,% m Pressure boundary partel
- 1. Fluid cylinder - S = 30,000 psi SA182-F304
- 2. Discharge valve stop S = 30,000 psi etuffing box and cylinder head extension, GA 479-304
- 4. Stuffing bor gland, S = 90,000 psi ASTM A461 GR. 630
- 5. Etuds, SA 193-B7 8 = 105,000 pai
- 7. Stude, cylinder tie, S = 105,000 psi SA 193-B7
- 8. Pump holddown bolts, T = 15,000 psi SAE GR. 1 Q = 12,000 poi
- 9. Power frame, foot area, 3 = 15,000 psi j cast iron j 10. Motor holddown bolts, T = 15,000 psi
! SAE GR. 1
' =
Q 12,000 psi i
- 11. Motor frame, foot area, S = 15,000 psi cast iron e
Amen dmen t le l
A ~
HCGS FSAR 1/86 l TABLE 3.9-Sn (cont) Page 3 ot 3 l all u;;;- c=1 el:trO c*---
Or ; - -"
Limitir.g Etrner, , j$ '
C. it; .- ia / Lc.- d ir. ' ' ' , "tr--- -;r- gwwk ammk -
$dz = Force on discharge nozzle flange in 2 direction. l Edx = Force on discharge tlange in x direction. l May = Moment or suction tlange about y axis. l Mdy = Moment on discharge flange about y axis. l Y
b Suction
,/ Nozzle
- l
,' ,/' I
/
x z
- Same axis orientation l applies to discharge l nozzle. l (83 Eased on ASME B6PV Codei Section III.
(28 Cowel pins take all shear.
(8) Nozzle loads produce shear loads only.
(*> Calculated stresses for emergency or faulted condition are less than the allowable stresses for the normal and upset condition stresses; therefore, the normal and upset condition is not evaluated.
(5 ) Operability: The sum of the plunges and rod assembly, pounds mass times 1.75, acceleratior. is misch less than the thrust loads encountered during normal operating conditions. Theretore, the loads during the f aulted condition have no significant ef f ect on pump operability.
I Amendment le l
'~
j [T HOGS FSAP 1/PL l TSBLE 3.0-59 (cort) Paqo 2 nt 3-allowable 'Iozzle l
..._____.L92d!DL,______. _ Oriteris
_ Forces and Mamants Forcen Actual t'ozzl<dI) and Mnment l
- 3. Hozz_}e The maximum moments fue to sce be1ow * (a) b j$gto g .,[e}
pipe reaction and the maximum * (b)
Loa _j n__La ul ed forces shall not ex: eed the allowable limits Desion cressure and temperature, Primary stress smaller of dead weight, thermal 0.75 Su or 2. 4 Sm expansion, safe shutdown earthquake (ASME Section III allowabla) l
- (a) Allowable limits (design bases) l y_! U2 E) tria, Fg = 9041 lo 9041 lb 40,739 lb 20,125 lb F y= 20,325 lb 20,325 lb 18,122 lb 20,325 lb Pg= 20,325 lb 20,325 lb 40,739 lb gost Ib Mg= 627,621 in.-lb 62',621 in.-lb 246,774 in.-lb 121,927 in.-lb My = 121,927 in.-lb 121,9 27 in.-lb 1,230,600 in.-lb 121,927 in . - lb Mg = 121,927 in.-lb 121,927 in.-lb 246,774 in.-lb 627,621 in.-lb
- (b) Forces ar d moments are given in global coordinate system defined on heat exchanger l outline drawings GE VPF 83239-97-4. l 1 de) Cataaewr> equr Fotees n *ke*W Oc64 *CG) i N1 L4Z. N5_ G
& 4544 ta SS LB 64cN LB 74M La Fy 42S3 ee 36Tl CB 5919 G sou tt Fa R22.is '#A+ La 'N32 'B p.97~7- LB
, Hg 5B,*4 % M -L6 M ,033- tM-lb .W , M 64-LS Iqq,cqlO g-tB g I S ,3~K m-LB r30,130 iM-2 3% ioS' 636 w- Lt 2X,52H m-lb sitt ,%2 m -lB 93G, ,961 84-LD L'qq nn-Lb it4,c3G oJ-Ls Hg ,
N60!= (.1) DdlllAW MW W h0D HOHGW AW WUEDW W Nk HEAT' EkCFMWW MZS D M M . IA(.fttL A @ W b3 Recre4c. 7ee terrER. 6E-%-24 bATsd J40uey at , l'184.
(W WAM@W@ A ACCT:es t:ty BY &&
Amendment 14 l f
N "'
HCGS FSAR 1/ M t. l TABLE 3.9-53 ( c )r. t) Pace 2 of J Limiting Allowante calculated Criteria Loading Component Stress Type inad Critarta In a <19 tuzzle load definit ion:
Turbine vendor has defir.ed allowable Inlet:
nozzle leads f or the turbine assembly. F = _ (16 2 0- e) W Em390 l The above calculated stresses assume thest allowable nozzle loads have been 3 7 b, satisfied Normal condition loads: g
- 1. Cesign pressure Exhaust:
2.
3.
Cesign temper 1ture keight of structure F= . (6 0 0 0 - M) W p gg l 4 Thermal expansion J
7 MON where: 1 F= resultant torce (It) m M= resultant moment (t t-in) W Upset, emergency, or fiulted condition loads: l
- 1. cesign pressure Irlet: kxf7.
- 2. tesign temperature F= ( 7 0 0 0-M) l
- 3. %eight of structure 4.7 /y (JPar - Frieso;H=f743 4 Thermal expansion
- 5. Eafe shutdown earthquake / operating basis earthquake Exhaust:
- F= vi%; H= t60C F= (HS00-M) E/<m- F= qss;H:1651
, 0.34 l but less tt n 7000 gpp l
, l r = resultant MP3T - E* fGMJH83Yr torce (It) @ g ~ p. g .g g l M= resultart FAucEI)- F Q6%;tt= 4%
moment (tt-lb) ,W
- /
I (t) calculated stresses for the faulted condition are lower than the allowable stresses for the normal plus upset condition; .therefore, the normal, upset, and emergency conditions are not evaluated.
(8) cperability: Analysis indicates that shaf t deflection with f aulted loads is 0.006 inch (tnis is fully acceptable) and ruximum bearing load witn faulted condition is 80% of silowable.
Amendment 14 l
T
(% R R IICGS FSAR TABLE 3.9-St (cont) Pace 3 ot 3 Limiting Allowabic calculated Criteria / Loading comLnnen t Stress Type 1,oa d 9 fMad)
Normal and upset condition loads: Fo = Allownble value Suction:
of Fi when all
- 1. Design pressure moments are zero Fo = 1940 .
pg a gg
- 2. Design temperature (LUD Mo = 2460 b IN
- 3. Weight of structure Mo = A110wsble value 4 Thermal expansion of Mi when all
- 5. Operating basis earthquake forces are zero Disenarge:
(f"r- LUS) Fo = 3715 m Rg = gg
' Mo = 4330 Laa.aa q, g Emerqency or faulted condition loads: C[
- HA)uH;tmCF THC Suction:
- 1. Design pressure R# 5 Fo = 2325 Me = 2950 pg ggg
- 2. Design temperature H[
- HAkMLot CF WC Hi: 1659
- 3. Weight of structure m@ L
- 4. Thermal expansion mgg pg -Lg Discharge:
- 5. Safe shutdown earthquake Po = 44SO f a qqq Mo e $200 gge gg4 cm) Calculated stresses for emergency or f aulted condition are less than the allowble f or normal plus upset condition; therefore, the normal and upset condition is not evaluated.
u) Operability: Static analyses for emergency or faulted condition show that the maximum shatt deflection is 0.002 in, with 0.006 in. allowable; shatt stresses are 3080 psi with 25,000 psi allowable; and bearing loads ior drive end are 99 lb, with 7670 lb allowable. Bearing loads for thrust end are 765 lb, with 17,600 lb allowabic.
(3) CALCidATet> lOES tages EVAUUDEb in) ACCGprGr> hY GcuGQaL M C TER 057tER- G5-86-3 I4TED dauu4ey at , W86.
5; h
\ '
't s
HCOS FSAP 1/Nb l TTDLE 3.9-5v ( co- t) Pa qe 3 of J l Componeat ard
{ Allowatile calculat ed(2)
Criterion Londini Controlling Stress -: -
f m _- p ll Nozzle Load Defisition: DD3 l Fcrces are in (lb) and moments The normal plus upset corditio- Fo = Allowable valite ot Fg l are it (ft-lt) the allowable loads it.clude: wner all moments are zero. l combiration of forces and moments (W) are as follows: Design pressure and tempera- Ma = Allowable valua ot M l ture, dead weight and thermal wner all torcas are zero.i l expar.sior, and operating basis OT-iES) l Fo Fg Mg earthquake. l
+ 5 1 Suctio, 10721e: l 9 Fo Mo F, = 5,5#U Pgzh9Q l r, Me = 14,3 N W Nng l Y
Disenarqa l rozzle: l ro = 7;sso pc.% i M Mo Mo = 15,3H4 N 13,q[ {
i The emerriency or taulted Y
Suction l con dit or. loads iriclude: norzle: l Fo = 6,6MU ZII"32 F[a g l Mo = 19,#50 W Ff[ssqql Design pressure and temperature, tf l dead weight and thermal Discharga corrie: l exparsion, and safe shutdown Fo = 9,420 W f;a$3l earthquake. M. = 1 N , e t,5 ,L44 a. gg, g3 Where F (1b s the maximum of the three orthogoaal f orces Fx , 7 l
1 Fg, F, ) i an is the maximum of any of the three ortnogoral moments l 02k Mx, My , M g ) ~for the same refernce coordinates. Fo and Ma for g upset and f aulted conditions are base values given above. l l
Note: 1 (s) 'Ihe calculated stresses for the ehergency or f aulted cor ditions are less than their {
corresponding allowable stresses for the normal plus Lyset condittor; therefore, rormal plus l upset condition is not evaluated. l l
(2.) CALCL1LAT5b jgf LLERG EVAUtATED A% M 6V
~~~
(px9a Etscretc Tu venn GB-74-M taEb danuAP4 &,l%
Amendment 14 l i
b
TABLE 3.11-3 Page 1 of 4
SUMMARY
OF HCGS COMPLIANCE WITH 10 CFR 50.49 This table represents a summary of Hope Creek Generating Station compliance with 10 CFR 50.49. ,
Paragraph (a) -
Requirement incorporated. A program has been established for qualification of electric equipment in a harsh environment that is safety-related. The present program will be discussed in detail by an E0 summary report as referenced in Section 3.11.
Paragraph (b) -
Requirements incorporated. Safety-related (1) electrical equipment, needed to mitigate 1 desigr?, basis events,/has been identified, l 4A5 BEEtt I desigreed andym l; OO qualified to function propedly in the environmental conditions during normal, abnormal and design basis events.
Paragraph (b) -
Requirement incorporated. [The criteria l (2) used to identify non safety cicctric equipment wh;;c f:ilurc cculd Offcci cperatier of cafety related equipment will be included in th sum :ry EO rc;crt. OTo date no non-safety-related equipment in thiscategoryhasbeenidentified[ y Paragraph (b) -
Requirement incorporated. The parameters l (3) required to be measured by Regulatory Guide 1.97 are included to the extent noted in Section 1.8.1.97.
, Equipment required by Regulatory Guide l.97
, to be environmentally qualified has been included in the equipment qualification program.
Paragraph (c) -
No requirement. This section details items (mild environment, seismic qualification, etc.) that are not included within the l scope of this rule.
L.
(
Amendment 9 l I
(
TABLE 3.11-3 (Con't) Page 2 of 4 Paragraph (d) -
Requirement incorporated. Table 3.11-5 has been developed to identify safety-related electric equipment located in a harsh environment. This table is included in Section 3.11 andcwill bdKncluded in the E0 summaryreport.p [pg g Paragraph (d) -
Requirement incorporated. The equipment l (1) evaluation summar (EES) sheets in the E0 summary report provide this information.
Paragraph (d) -
Requirement incorporated. Equipment test l (2) reportsperFH provide this information.
Paragraph (d) -
Requirement incorporated. The EES sheets l (3) in the EO summary report __ provide this information.
Paragraph (e) -
Requirement incorporated. Section 3.11 l (1) discusses the design basis including
- , temperature and pressure. A plant specific profile for temperature and pressure vs. 3 '
time for equipment qualificationswill bei included in the EQ summary report. lWAS D85*>l Temperature and pressure limits are included on the EES's and in Table 3.11-1.
Paragraph (e) -
Requirement incorporated. Humidity has l (2) been considered where it is applicable and is included on the EES's and in Table 3.11-1.
Paragraph (e) -
Requirement incorporated. Chemical l (3) effects are not applicable since demineralized water is used. Effects on demineralized spray are encompassed by testing at 100% relative humidity.
j pg 3g33 'I Equipment subjecteduto direct spray impingemen00will L6 evaluated to determine if testing under spray conditions in addition to 100% relative humidity conditions is required.
Amendment 9 l
. v_r --
^(
TABLE 3.11-3 (Con't) Page 3 of 4 Paragraph (e) -
Requirement incorporated. Radiation l (4) effects on safety-related electrical equipment have been taken into account, where applicable, including radiation i
resulting from recirculating fluids.
Radiation levels are included on the EES's and in Table 3.11-1.
Paragraph (e) -
Requirement incorporated. Aging is l (5) included as part of equipment qualification except where equipment is not considered to be age sensitive. Qualified life is included on the EES's.
Paragraph (e) -
Requirement incorporated. Equipment that l (6) could be submerged has been identified and demonstrated to be qualified by test for the duration required.
Paragraph (e) -
Requirement incorporated. Synergistic l
/_
(7) effects have been considered in the accelerated aging programs. An engineering
- m. evaluation will be performed to identify known synergistic effects for materials that are included in the equipment qualified. Any identified synergistic effects are accounted for in the qualification programs. Section 3.11.2.7.4 discusses the design basis for synergistic effects.
Paragraph (e) -
Requirement incorporated. The equipment l (8) technical specification included the margin in the environmental conditions of the plant and the margin to be applied to -
service conditions. Section 3.11.2.7.1 discusses margins as part of the design basis.
g5 n0uS 3,g,3 g ,m,3,, g, gg y Paragraph (f) -
Requiremen incorporated.h!Scction 3.11.5.S l (1-4) discuss performance of environmental qualification.py tccting and sn lysis.j m Y
w-Amendment 9 l
,f - j -
HCGS FSAR I/86 TABLE 3.11 6 Page 3 of 3 S AFETY.RELATED EQUIPMENT LOCATED IN A HARSH ENVIRONMENT EXD4PTED FROM ENVIROt04 ENTAL OUAllFICAll0N REQUIREMENTS EQUIPMENT TAG pc. MPL NO. DESCRIPTION REASON 1-BC.SV.F041D Ell Solenold Velve These solenold velves and position switches perform no safety functions.
No Tag No. Ell.F04tD Position Switch However, because of their association with a IE power supply, they have 1-0C.SV-F050A Ell Solenold Velve been provided with primary and backup protective devices.
No Tag No. Ell-F050A Posttlon Switch I-DC.SV-F0508 Ell Solenold Valve No Tag No. E 11.F0508 Position Sultch 10.P.219 RCIC Vec Pump % tor Space Heater They are protected by primary and tackup IE trenkers.
10-P-220 RCIC Glend Seal Cond. Motor $3 ace Heater I.FC.TSH.4277 Temp. Switch High Provide alarm function only. Determined by analysis that no fault condition (ground, 1-FC.TSH-4278 Temp. Switch High open or short circult) can impact the 125V de safety related power tus.
1-FC-LSH-4298 Level Sw. High 1- FC-HV-'Q91 McTee.CDEeA1EE) VAug Twts RCIC SYssn maat acerteD W.W TG5trN3 se SA8%Ty Aacic45. lbonelt IRAuT,6 CF ffr V.5ErATk*J 60ffM A C4As .1E PouMR St4P5t.v,ir 145 9tD3 Pee VihEb WTW FeSAP A@ DCRtJP PROTEcrtus DevM.
Note: All of the equlpment In this table Is quellflod for its function In In accordence with 10CFR50.49 requirements.
?
Amendment 14
1 l
i \m
- 6.2.4.3.2.17 Plant Leak Detection System Lines 1,
2 The two plant leak detection lines penetrate primary containment and connect directly to the primary containment atmosphere. Each
. line is isolated by two motor-operated globe valves, located outside primary containment, that receive a containment isolation signal.
6.2.4.3.2.18 Hydrogen / Oxygen Analyzer Lines The eight hydrogen / oxygen analyzer lines penetrate primary containment and connect directly to the primary containment atmosphere. Four of these . lines penetrate the drywell, and the a
remaining four, penetrate the suppression chamber. 6 /of the 'M eight lines are isolated by two motor-operated globe valves located outside containment. IT.7e one ::mcining lin i: 10 !:ted by five meter-eperated g!che valver, One valve of which is located : cic;c :: p :cible te the pri=:ry'rentainment and the othcr four valve cre located ir : rallel en br:nchin; lines.
6.2.4.3.2.19 Primary Containment Instrument Gas Header Line The primary containment instrument gas header to the suppression chamber supplies instrument gas to vacuum relief valves located there.. This line is isolated by two air-operated globe valves outside primary containment. Each valve receives a containment isolation signal.
j 6.2.4.3.2.20 Integrated Leakage Rate Test Lines The integrated leakage rate test (ILRT) lines are not used during i normal plant operation. 'They are isolated by two manually locked-closed globe valves, one inside and one outside primary ~
containment.
i.
6.2.4.3.2.21 Instrument Lines.
-Each instrument line that penetrates the primary containment and is connected directly to the containment atmosphere is isolated by a manual valve. This design is justified on the basis that f'- system reliability is greater with a manual isolation valve, that
(.~ these systems are closed systems outside containment designed to 5
{ 6.2-59 l
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, ,, ,,,.w,, n .-.,,nn,.. , . . . , , -,
HCGS FSAR with increasing temperature, the decrease in the corrosion rates can be attributed to the depletion of oxygen available. Thas, these corrosion rates show that reaction b. is dominant in the oxygen-rich lower temperature water, and reaction a. becomes dominant with increasing temperature.
Van Rooyen, in Reference 6.2-20, determined the corrosion rate of zine from the available data but did not differentiate whether the corrosion was due to reaction a. or b. Thus, Van Rooyen's calculated corrosion rate does not accurately present the hydrogen generated from the corrosion of zinc.
The data of References 6.2-18 and 6.2-19 on hydrogen generation from zinc corrosion are bounded by the following corrosion rate: -
H (2n) = 3.76 x 10-' exp (0.0218T) Ib-moles /ftz-h where:
T= temperature, OF This rate equation is used to calculate the hydrogen released due I to zine corrosion and corrosion of zine paint by conservatively \
assuming that all corrosion is caused by reaction a.
Since containment spray water does not contain any chemical
,lWS971 additives, the pH of the LOCA water is approximately 7. At this pH, the corrosion rate of aluminum is negligible even at high temperatures, as discussed in References 6.2-15 and 6.2-16.6 eMId Therefore, aluminumhin the containment 633not assumed to be the source of any hydrogen generation. A 6.2.5.3.4 Hydrogen Existing in Reactor Coolant
~
During normal operation of the reactor, free hydrogen exists in the coolant water in concentrations of 10 to 50 sec/kg of coolant. Although it is unlikely, it is assumed that all of this hydrogen is stripped from the coolant at the time of the LOCA.
The total amount added to the containment atmosphere (corresponding to a concentration of 30 scc /kg of coolant) is listed in Table 6.2-21.
6.2-82
INSERT FOR PAGE 6.2-82 The corrosion rate of copper at this pH is negligible per Reference 6.2-15.
( ,
TABLE 6.2-14 MONITORED AND ALARMED l OPENINGS IN REACTOR BUILDING ENCLOSURE Access Near Column Opening Elev, ft Coordinates Tvoe of Access Openino Number 4304 102-0 13.6, T Pressure-tight door l 4323A 102-0 13.6, U Pressure-tight door 4313A 102-0 21R, Md Pressure-tight door l 132-0 21R, V Equipment hatch 132-0 16R, V Equipment hatch 132-0 18.9, W Equipment hatch
- 132-0 15R, P Equipment hatch Iau-chu-oQ' 3 2-OPb ' 18.9, V Blowout panels 4501A 145-0 17R, P Pressure-tight door
5-0 !8.9, " Bleecut panele g_,,
162-0 19.9, V B10ecutpanclb 4302 102-0 22R, Md Pressure-tight door l 132-0 18.9, N Steam tunnel ventilation barrier
(
Amendment 8
't TABLE 6.2-21 Page 1 of 2 l PARAMETERS USED IN EVALUATING THE PRODUCTION OF HYDROGEN FOLLOWING A LOCA Parameter Value Reactor thermal power for 1095 days 3440 MWt Drywell free volume 1.6 x 105 ft3 Suppression chamber free volume 1.335 x 105 ft3 Zircaloy cladding surrounding active fuel Mass 76,250 lb Surface area 74,870 fta Zine (as galvanized steel) in drywell Mass 7629 lb Surface area 59,600 ft2
': Zinc (as galvanized steel) in suppression chamber Mass 859 lb Surface area 6150 ft2 Zinc paint in drywell Volume of paint 4.03 ft3 Surface area 36,400 fta Aluminum in drywell(1) 4,455 15 _A -
[W:ce Strf ren{. 200 ft? 1 Copper in Drywell(1)
Mass i f?? 200 lb h
' ' ,, 3 02 Et L 7' Surface rca l }
Volume of free hydrogen normally in reactor 195 ft3 coolant (at 600F and atmospheric pressure)
MSIV air inleakage rate (scfh/ valve) 11.5 l
(2) The analysis to show the acceptability of the HCGS hydrogen i
'. recombiner system did not include the hydrogen contribution !
from corrosion of aluminum or copper. Reanalysis to include :
Amendment 8 l
HCGS FSAR 10/84 TABLE 6.2-21 (cont) Page 2 of 2 l this contribution would show no impact on the hydrogen recombiner initiation due to HCGS recombiner initiation being controlled by the oxygen concentration rather than the hydrogen concentration. In addition, reanalysis would show only a negligible impact on the total hydrogen generated over the course of the event if corrision of aluminum and copper was included.
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' ** KEY: l l REACTOR BUILDING ENCLOSURE ACCESS OPENING J@
A-4646-1, REV 4 HOPE CREEK GENERATING STATION FINAL SAFETY ANALYSIS REPORT REACTOR BUILDING ENCLOSURE BOUNDARY OUTLINE-PLAN AT EL. 162*-0",178'-6" I 9 l 3 l 2 FIGURE 6.2 23 AMENDME NT 8,10/84
i i
- b. RHR shutdown cooling Reactor Prevents valve open- .
injection,-motor- pressure ing until reactor
' operated, F015A, B pressure is below system design pressure i
- c. RHR reactor head Reactor Prevents valve open-spray, motor-operated, pressure ing until reactor F022, F023 pressure is below system design pressure
- d. RHR low pressure cool- Reactor Prevents pressurization ant injection (LPCI), pressure of the low-pressure motor operated piping upstream of valve ,
F017A,B,C, and D 4
- e. Core- spray injection, Reactor Prevents valve motor-operated, F005A,B pressure opening until reactor pressure is below system design pressure The RHR shutdown cooling suction isolation valves, reactor head spray valves, and shutdown cooling injection valves have 1 redundant interlocks to prevent the valves from being opened when 1 , the reactor pressure is above the system design pressure. These
/
valves also receive a signal to close when reactor pressure is t _
above the system design pressure.
Although the LPCI injection valves, MO F017A, B, C, and D, are interlocked to prevent opening when the pressure downstream of the valves is high, the injection line check valves F041A, B, C, pgg.gp' and D and the relief valves F025A, B, C, and D provide additional overgressurization protectionA f Rectine veritientien Of a ler ch::: v:lve 1e:h r:t: i: ::: rpliched by op;nin; ment:11y Operated drain line valve: FOSS nd F05? :nd deter =ining th:t the pre : ree scree the injection v:lve: cre 1;u:::d, els ny 10:h ; ::y be OS::rved thrsagh th; inst:11;d f1;; sightgles;es l 100 70 4004A 0 in the drain lin;;. Thi; ::;;;;; th;t th; 10; _
- f"'
pre:: ie piping eill net bc ;; rpr;;;;ri;;d during reutine
- rveill_n:: :nd ;;;r:bility testing Of th: inj :ti:n v:17 :. i ,
l The core spray injection valves MO F005A and B are prevented from opening until reactor pressure is low enough to prevent system '
, overpressurization. Reactor pressure is sensed by four pressure transmitters in a one-out-of-two-twice configuration for each L core spray injection valve.
7.6.1.3 Leak Detection System - Instrumentation and Controls
! The safety-related portions of the LDS are ac follows:
r i.~(
, 7.6-3 Amendment 11 i
i 9
9
- , ,- --w, , , , , - - - , - , , , , , - - - - . , - , - , , , - - - -
,.,,y.y..,-n,
, - _ m . , . - , ,, ,, ,e ..n.,,. ., ,,.g. ,
INSERT FOR PAGE 7.6-3 Inservice testing of the RHR injection valves will be performed during cold shutdown only, therefore overpressurization during surveillance will not be a concern. -
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HCGS FSAR With a control rod selected for movement, depressing the " withdraw" switch energizes the insert valves at the beginning of the withdrawal cycle to allow the collet fingers to disengage the index tube. When the insert valves are deenergized, the withdraw and settle valves are energized for a controlled period of time.
The withdraw valve is deenergized before motion is complete; the drive then settles until the collet fingers engage. The settle valve is then deenergized, completing the withdraw cycle.
This withdraw cycle is the same whether the " withdraw" switch is held continuously or mooentarily depressed.
The timers that control the withdraw cycle are set so
, that the rod travels one notch (6 inches) per cycle.
Provisions are included to prevent further control rod motion in the event of timer failure.
A selected control rod can be continuously withdrawn if i the
- withdraw" switch is held in the depressed position at the same time that the " continuous withdraw" switch f is held in the depressed position. With both switches t '
held in these positions, the withdraw and settle -
commands are continuously energized, and the selected rod will continuously withdraw until the buttons are released and the withdraw timer completes its cycle or a red block is generated.
7.7.1.1.2.2 Rod Block Trip System The rod block trip portion of the RMCS inhibits movement or selectier, of control rods upon receipt of certain input signals.
lA SHALAP]
i
) Mha the sam-Fgrouping reactor protection of neutron system monitoring (RPS) is GEe u$used pment in that the is used rod in block circuitry. p Half of the total monitors, the source range monitor (SRM),
intermediate range monitor (IRM), average power range monitor (APRM), and rod block monitor (RBM), provide inputs to one cf the RMCS rod block logic circuits and the remaining half provide inputs to the other RMCS rod block logic circuit. The -
recirculation flow comparator trip units input rod block trip
(/..
7.7-6
, -y, , , -. .
n, _- -
g- HCUS FSAR 10/03 isolation va1ve. e is clascifled Selsnic_Qategor_y__I. fThewsbedded oup-C-outA+ aM-i-nelud H+c -the-piping-ic 4-reat-ionc!asM44<,4-OuaMtt@lYhe
/almmH4fec exposed portion of eacE~ drain line downstream of the Geisnic Category J boundary is classified non-Seismic Category I, but is seismically analyzed up to an anchor or the piping _ terminus since it is connected to Seismic h
Catecory I pipinWTh-$ ping-4ownstrean-bb-sack-wolateo.wysIW\
Ms-Masra4+ed--Guam 4.v-Grour>-Dj
[T;c wpu, ruuufr'/ kmP coC@ CAT 7cM ' c. CWow oJ Frdus qll -y. }
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The 1-inch drain lines are individually routed thrcugh tne concrete. Because drains number 12 and 15 terminate above the same floor drain collection hub, the seven fuel pool lines terminate above six different radwaste floor drain Gyctem collection hubs. Each drain line includes a manual globe-type isolation valve.
The source of a liner Icak can be identified to the extent that leakage from an individual drain line will be due to a source within the liner leakage area corresponding to that line, as shown in Table 9.1-17. Any leakage will be detected by the periodic visual observation of each drain hub that is required by
, station procedures. Liner leakage can also be detected from the main control room by observing an increased frequency of operation of the normal fuel pool water makeup system or of the reactor building floor drain sump pumps.
If a leak is not detected by the above methods, and is cf magnitude greater than the normal makeup system, the fuel pool skimmer surge tanks low-lowilevel alarm in the main control room will signal the leak. Fuel pool low level is also alarmed in the main control room, and serves as a backup to surge tank low-low level for detection of a lince leak.
The liner is not within the jurisdiction of ASME Section XI and is, therefore, not subject to the HCGS inservice inspection program. The appropriate level of inspection is provided by the station administrative procedures, which require visual inspection of the drain lines. Because the leak detection channels behind the wall and ficor liner plates are not designed to be pressure tight, and because the leak detection piping cannot be isolated and pressurized, no tests of the leak detection system are planned.
Control rod storage hangers on the spent fuel pool walls provide storage for 185 control rods.
9.1-10a Amendment 2
u - a_m . _. a _ _-. - 4 . #, _# .._-____.# u , _..~..a , _. .
i
~
cranes and designed to be simultaneously supported by the main hoist of each crane, is used to lift the 366-ton stator of the turbine-generator unit.
- 1. Feedwater heater removal hoist (IAH103, IBH103)
These portable 24-ton capacity, manually (chain) -
operated hoists are designed to operate in tandem on one of the nine I-beam monorails located above elevation 120 feet in the turbine building. The beams serve the nine condenser-mounted feedwater heaters.
, The hoists are used during feedwater heater tube
! removal.
l
} m. Heating and ventilating equipment removal hoist t
(10H104) 4 This 15-ton capacity monorail hoist is located above elevation 171 feet in the turbine building. It is used i j for moving heating and ventilation equipment through
- ( the equipment removal hatch at el,evation 137 feet.
t i n. Motor-generator set hoist (OAH105, OBH105)
I These 15-ton capacity monorail hoists are located above elevation 137 feet in the turbine building. They service and replace components of the two reactor i recirculation pump motor-generator sets. /
- bMGERT,1
- o. Secondary cond_ensate pump hoist (10H106) :
3 This 15-ton capacity monorail hoist is located above
- elevation 54 feet in the turbine building. It services i the three secondary condensate pumps and their electric motor drivers from one common monorail. j
- p. Reactor feed pump hoist (IAH107, IBH107, ICH107)
- t# ,
These 15-ton capacityl ch;i; ,;;;;t;dimonorail hoists
.e are located above elevation '37 feet in the turbine s
9.1-93 Amendment 8 1
4
~.----m- w-,- - - , , = - ..ww--., m,-e, -,-a,m- ,,,m,- -..w= > -- -,n,p--~n,,- -.-w,,-- - - - , - - - - .<r <r,,- e w , , , ~-,ar-
INSERT FOR PAGE 9.1-93 Both hoists operate together on the same rail to lift those components such as the motor and exciter, or the generator, that weigh more than 15 tons.
i
9.1.5.3.2.2 RPV Head Strongback The RPV head strongback is used as a lifting device for the following loads:
- a. Drywell head
The RPV head strongback is a special lifting device as defined by NUREG-0612, Section 5.1.1.4. The design factors of safety versus yield and ultimate strengths are provided in Table 9.1-14. The RPV head strongback design Mill be up r:d:d tc,' meets the single-failure-proofguidelinesofpNUREG-0612, Section 5.1.6gG)(a).
The RPV and drywell heads each have four lift points. The lift points meet the single-failure-proof guidelines of NUREG-0612,
' C Section 5.1.6(3)(a).
The RPV head insulation and its support structure is carried over the RPV when the head is on. The support structure is lifted in two pieces. The lift points on each piece are designed to meet the single-failure-proof guidelines of NUREG-0612, Section 5.1.6(3)(a).
In summary ithe RPV head strongback and the associated heavy load lift points!bil11 satisfy the single-failure-proof guidelines of NUREG-0612, Section 5.1.6. A postulated heavy load drop is not considered credible due to the single-failure-proof design.
t 9.1.5.3.2.3 Shield Plug Sling i
The special lifting device for the reactor well shield plugs and the dryer-separator pool plugs is single-failure proof in accordance with NUREG-0612, Section 5.1.6(1)(a). The design
- factors of safety versus yield and ultimate strength are provided v in Table 9.1-14. Each plug has four lift points to prevent.
t
(
9.1-103 Amendment 12 i
N" p+ ***
Q* -,ehm._,% .g .-
e-
HCGS FSAR 09/85 uncontrolled lowering of the load, assuming a single lift point failure. Each lift point has a maximum combined static plus dynamic design safety factor of areater than 5 with respect to material ultimate strength. The design is conservative and satisfies the single-failure-proof guidelines of NUREG-0612, Section 5.1.6(3)(a). A postulated heavy load drop is not considered credible due to the single-failure-proof design.
9.1.5.3.2.4 Dryer-Separator Sling The dryer-separator sling lifts the steam dryer and the moisture separator. The sling design satisfies the guidelines of ANSI N14.6-1978 in general, but does not explicitly comply as recommended by NUREG-0612, Section 5.1.1(4). The design factors of safety versus yield and ultimate strengths are provided in Table 9.1-14.I They re lerc ther. the value: Of 3 versus yield JA-Isad 5 vcrsus ultimate required by Sectier 5. ' . ' ) .
The dryer-separator sling Nill be upgraded O' satis the single-failure-proof guidelines of NUREG-0612, Section 5.1.6(1)(a). The moisture separator and the steam dryer each have four lift points. The lift points meet the single-failure proof guidelines ,
of NUREG-0612 Section 5.1.6(3)(a). A postulated heavy lead drop (
is not considered credible due to the single-failure-proof design. .
9.1.5.3.2.5 (Deleted) 9.1.5.3.2.6 Service Platform Sling 4
The service platform sling lifts the RPV service platform. The sling design satisfies the guidelines of ANSI N14.6-1978 in general, but does not explicitly comply as recommended by NUREG-0612, Section 5.1.1(4). The design factors of safety versus yield and ultimate strengths are provided in Table 9.1-14. 3d i
i l l
9.1-104 Amendment 12 1
g _ , . .
NCGSFSAR 10/84 O -
f::tcr ver :: yield is grc;ter th:n the V:le: Of 2, leer thir the value Of 5 nd th:
re:uired by i
f :ter ver :: ulti=:t C ction 5.1.I'4} cf N"nCC 05 2.1 The RPV service platform has three lift points. The platform is handled as close to the refueling floor as is practical.
The serviceiolatform slina and the lift points on the service platform !vi'll be urcr ded te! meet the single-f ailure-proof guidelines of tiUREG-0612, Section 5.1.6. No load drop analysis is required due to the single-failure-proof design.
Fuel Rack Lifting Fixture l 9.1.5.3.2.7 The fuel rack lifting fixture will be used for several non-routine heavy load lifts over the fuel pool. It is used for installing the spent fuel rack modules. As described in Section 9.1.2.2.2.2, a base capacity of 1078 spent fuel cells plus 30 multipurpose cavities will be installed for initial plant operation. The remaining capacity of 17 rack modules, providing an additional 2976 cells, will be installed during plant
.- operation. The lifting fixture design factors of safety versus yield and ultimate strengths are provided in Table 9.1-14. These i' factors meet the criteria of paragraph 5.1.6(1)(a) of NUREG-0612 for a single-failure-proof single load path special lifting device.
The lifting eye of the fixture is connected to the crane hook by a sling arrangement. The slings are selected to meet the single-failure-proof criteria of Section 5.1.6(1)(b) of NUREG-0612. The four legs of the fixture each have a J-shaped plate N at the bottom. The fixture legs are lowered through four of the empty cells of the rack module being lifted, moved horizontally a short distance, and raised to hook to the module base. The'four l J-shaped plates contact the underside of the module base when it is being lifted. This design eliminates the need for lifting ;
eyes on the module. The weight of the module, together with the i shape of the lifting fixture plates, provides assurance that the j fixture is securely attached to the module during lifting.
'N .
Thus,, because there.are no lift phints on the modules, and both the crane and lifting fixture.are single,-failure-proof, the modules will be installed with a single-failure-proof handling system. A postulated heavy load drop is not> considered credible due to the single-failure-proof design. -
/ ,
9.1-105 -
Amendment 8 h $% 0
!<,-,,-,,---,-n- - , - , , . , ,
The modules will be lifted with the main hoist of the polar crane. Limit switches and travel stops, described in Section will be temporarily bypassed as necessary to permit 9.1.5.2.1.5, the main hook to travel into the main hook exclusion area shown on Figure 9.1-31 when the modules are installed. The temporary bypassing of limit switches and travel stops will be done under strict administrative control.
RPV Stud Tensioner Sling l 9.1.5.3.2.8 WSERT L A _. The RPV stud tensioner has four lif: points.Ilf The tensioner isl 4 handled as close to the refueling floor as is practical. / The stud tensioner litting device consists qt four slings supplied with the tensioner. The tensioner sling design factors of safety
, versus yield and ultimate strengths are provided in Table 9.1-14.
The factors calculated for the maximum combined static and
- dynamic load, assuming the entire load is carried by only two of the four wire ropes, are greater than the values of 6 versus of j yield and 10 versus ultimate required by paragraph 5.1.6(1)(a)
NUREG-0612 for a single-failure-proof single load path special
) lifting device.
i i
d>Th'e RPV stud tensioner is carried over the RPV while the head is p__ ( ~
INSE87gn.gfApotentialdrepeftheRP"studterrierer-culd-eterrre
.;r. d:er; er unneceptable le:hege becture the drep reeld be f lL- 1 :: ::ver th:n : dryu 11 er RPV he:d drep. A :n:lyri ef :
p :tul:ted lord drep :;2inct the feur evalectic. -
criteri: Of 9.'-22.
NUKEG-00 2, Section 5.1, is provid d in T:ble
} 9.1.5.3.2.9 Miscellaneous Single Failure Proof Slings l Single-failure proof slings selected in accordance with NUREG-i 06,12, Section 5.1.6(1)(b), are used to lift the following loads:
' - Spent fuel pool slot plugs l
- Spent fuel pool and cask pool gates l '
l l Head stud rack l ,
- Flux monitor shipping crate l l
- 4'x4'-6" hatch cover l 10'x10' hatch cover l G=
9.1-106 Amendment E i
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Refueling bellows guard ring _ . l Jib crane l The fuel pool slot plug sling is a single-failure-proof conventional sling selected to meet the requirements of NUREG-0612, Section 5.1.6(1)(b), as clarified by FSAR Section-9.1.5.1.n. Each fuel pool slot plug has a single lifting point designed with a maximum combined static plus dynamic factor of safety greater than 15 with respect to material ultimate strength. This satisfies the NUREG-0612, Section 5.1.6(3)(b)
. requirement for a safety f actor:of 10. A postulated heavy load drop is not considered credible due to the single-failure-proof design.
A single-failure proof conventional sling selected in accordance with NUREG-0612, Section 5.1.6(1)(b), as clarified by FSAR Section 9.1.5.1.n, is used to lif t the fuel ' pool and cask pool gates. The pool gates are the only heavy l'oads which must routinely be carried over the fuel pool. There are two lift points on each fuel pool gate. A single lift point failure will not result in an uncontrolled lowering of the gate. The lift
(-
points are designed with a maximum combined static plus dynamic factor of safety greater than 15 with respect to material ultimate strength. This satisfies the NUREG-0612, Section 5.1.6(3)(a) requirement for a safety factor of 5. A postulated heavy load drop is not considered credible due to the single-failure-proof design.
'M C The RPV head stud rack has a single lifting point.k The stud rack is lifted by a sling selected to meet the single-failure-ptcof
. guidelines of NUREG-0612, Section 5.1.6(1)(b), as clarified by FSAR Section 9.1.5.1.n. The stud rack is handled as close to the -
refueling floor as is practical, and is only carried over the RPV pcay while the head is on. The RPV head stud rack is not carried over LB the spent fuel pool.\ l.^.r 2n:lyri: Of 2 p::ttl:t:d dr:p :grinct i t.is four avaluation criteric of NUREC-0512, Section 5.!, is-
- providad in Tabic 0.1 22. ' potential dr;p w:uld :t :::: feel d:::gr ar ::::: pt:ble 10 h:;; b:::::: the dr;; rc Id be 10:0
- th
- n : drJu:11 : P.?'? herd dren.
The flux monitor shipping crate is carried over the refueling' floor =by slings selected to meet the single-failure-proof guidelines of NUREG-0612, Paragraph 5.1.6(1)(b), as clarified by FSAR Section 9.1.5.1.n. The shipping crate is not carried over
,' the RPV or spent fuel pool. An analysis of a postulated drop
(_.
9.1-107 Amendment 8 i
) ,
_ _ - . . ~ - . , _ _ _ _ _ _ . _ . _ _ . . . . _ . _ . . . _ . _ _ _ _ _ _ _ . _ . _ _ . _ _ _ , . - _ , _ . _ _ _ . _ , . , _ . _ ,
INSERT A FOR PAGE 9.1-106 The lift points satisfy the single-failure proof guidelines of NUREG-0612, Section 5.1.6(3)(a).
INSERT B FOR PAGES 9.1-106 and 107 A load drop is not considered credible because of the single-failure proof handling system.
INSERT C FOR PAGE 9.1-107 The lift point satisfies the single-failure-proof guidelines of NUREG-0612, Section 5.1.6(3)(b).
t
A 4
1 HCGS FSAR 10/84 cgainst the four evaluation criteria of NUREG-0612, Section 5.1, is provided in Table 9.1-23.
The 4'x4'-6" hatch cover and the 10'x10' hatch cover are carried over the refueling floor by slings selected to meet the single-failure-proof guidelines of NUREG-0612, Section 5.1.6(1)(b), as clarified by FSAR Section 9.1.5.1.n. The hatch covers are not carried over the RPV or the spent fuel pool. The lift points on the hatch covers satisfy the single-failure-proof guidelines of NUREG-0612, Section 5.1.6(3)(a). A postulated heavy load drop is not considered credible due to the single-failure-proof design.
The refueling bellows guard ring is carried over the refueling floor by a single-failure proof sling se'lected to meet the guidelines of NUREG-0612, Section 5.1.6(1)(b), as clarified by FSAR Section 9.1.5.1.n. The guard ring is not carried over the I
spent fuel pool and is only carried over the RPV when the RPV head is on. An analysis of a postulated drop against the four i evaluation criteria of NUREG-0612, Section 5.1, is provided in Table 9.1-23.
The fuel pool jib cranes are carried over t.he reactor vessel when -
the RPV head is off, but only when the RPV service platform is in (
place on the RPV flange. A conventional sling, selected in accordance with NUREG-0612, Paragraph 5.1.6(1)(b)(ii), as -
clarified by FSAR Section 9.1.5.1.n., is used to lift the jib crahe. The load used to select the sling is two times the sum of the maximum static plus dynamic loads. The dynamic load is assumed to be 0.25W, where W equals the weight of the jib crane.
The load used is, therefore, 2(W 0.25W). The jib crane design has a single lift point with a design safety factor of 10 times the maximum combined concurrent static and dynamic load with respect to material ultimate strength as required by NUREG-0612, Paragraph 5.1.6(3)(b). The jib crane handling system, therefore, meets the single-failure-proof guidelines of NUREG-0612, Section 5.1.6. A postulated heavy load drop is not considered credible due to the single-failure-proof design.
9.1.5.3.2.10 Channel Handling Boom Crane l
$@ The channel handling boom crane isN11fted by the ::iliary hech. 7--
lifting defice 10 nece ::ry 2: the b000 crane cer9ects /
15directly te the mus444:ry 500h Of the pelar crane. . l l
l i )
2 9.i-10e Amendment B b
l l
I
1 g-
\ The channel handling boom crane is not carried over the RPV or EG82T spent fuel pool.% ' Table 9.'-22 prcride: er er. lyri: Of a, 7-B postu;;;cc crop against the four evaluation criteria of MURSO
,05!2, Sectier 5.' -
9.1.5.3.2.11 New Fuel Inner Box Lifting Sling l The inner box lifting sling is used to lift the metal new fuel shipping container out of the wooden shipping crate, and from the
- new fuel receiving area at elevation 102 feet up to the new fuel
! inspection area at elevation 201 feet. The sling consists of a single ring for attachment to the polar crane auxiliary hook, and four stainless steel wire rope legs with safety swivel hooks for attachment to the four lifting lugs on the metal box. The sling is a special lifting device according to the definition in Section 1.2 of NUREG-0612.
Although not originally specified to be designed in accordance with ANSI N14.6-1978, as necessary for strict compliance with Paragraph 5.1.6(1)(a) of NUREG-0612, the sling is provided by GE under appropriate quality assurance requirements and quality
, control procedures for the specific dedicated application of 2
( '- lifting the inner new fuel shipping container. These quality 2
requirements include a certificate of inspection for the sling, j and liquid penetrant inspection of the ring and the swivel hooks.
1 The calculated inner box lifting sling factors of safety versus yield and ultimate strengths are provided in Table 9.1-14. The factors are greater than the 6 versus yield and 10 versus i
ultimate strength values required by Paragraph 5.1.6(1)(a) of NUREG-0612 for a single-failure-proof single load path special lifting device.
i The critical (load bearing) components of the inner box lifting sling are the ring, splicing sleeves (8), wire ropes (4), and swivel hooks (4). Repair or replacement of these components, if necessary, will be done under controlled conditions.
The inner box has four lift points. A single lift point failure
- will not result in uncontrolled lowering of the load. The l
calculated factor of safety under the maximum combined concurrent static and dynamic load after taking a single lift point failure meets the value of 5 versus ultimate required by Paragraph l
/*.
5.1.6(3)(a) of NUREG-0612 for a single-failure-proof design.
. The '
s <
i 9.1-109 Amendment 10 ,
y - ~ , - _ . - . _ - _ .
I
' INSERT A FOR PAGE 9.1-108 i
. carried over the refueling floor by a sling selected to meet the single-failure-proof guidelines of NUREG-0612, Section 5.1.6(1)(b) as clarified by FSAR Section 9.1.5.1.n.
i
! INSERT B FOR PAGE 9.1-109 The lift point on the channel handling boom satisfies the single-failure-proof guidelines of NUREG-0612, Section.
5.1.6(3)(b). A load drop is not considered credible because of the single-failure-proof handling system.
l i-1 l
i i
e 4
1 T
P i
._. _ . _ . . _ , . - _ . _ . _. .. _ _ _ . . - - . . . , ~ . . . _, _ _ _ . . .
HCGS FSAR 7/85 Two hoists, one mounted on each monorail, work in tandem to remove a SACS heat exchanger return end cover. The configuration includes a separate sling and lifting point for each hoist.
There is no safe shutdown or decay heat removal equipment beneath the load paths on elevation 102 feet or on the next lower elevation (77 feet). But the 18-inch RHR heat exchanger A inlet line, three Channel A Class IE cable trays, and some Channel A, Class IE conduits are located in the northwest corner of the RHR heat exchanger A compartment below elevation 77 feet and beneath a portion of the SACS heat exchanger A hoist load path. The 18-inch RHR heat exchanger B inlet line and two Channel B Class 1E cable trays are located beneath the load path on elevation 77 feet. Three additional Channel B Class IE cable
. trays and some Channel B Class IE conduits are located in the southwest corner of the RHR heat exchanger B compartment below elevation 77 feet and beneath a portion of the SACS heat exchanger B hoist load path.
, To preclude the possibility that a dropped SACS heat exchanger end cover could penetrate the elevation 102 feet floor, the cover lift height will be mechanically restricted to the minimum necessary distance above the floor, and energy absorbing material will be placed beneath the loai path, or another load handling system that satisfies the four evaluation criteria of Section 5.1 3of NUREG-0612 will be us.ed.
Therefore, these hoists satisfy guideline 5.1.5(1)(c) of NUREG-0612.
nn. Recombiner system hoists (00H318,.10H318)
This hoist does not handle heavy loads.
(
\m 9.1-123 Amendment 11
_ =-
l' F%uRE 9. I- 10 (cameuco OVERHEAD R Equipment Item Tag Floor Elev toc rig Colum Number Crane or Holst Number Building Number Area (ft) 1 Reactor building polar crane 10H200 Reactor 201 1.2-32 N-Vili 2 Personnel air lock hoist 10H217 Reactor 102 1.2-28 P-R321 3 Recirculation pump motor 1AR201 Reactor 102 1.2-28 Sa-Qp' hoist 1BH201 (Drywell) Sa-Tp' 4 Reactor water clean-up filter / 1AH220 Reactor 178-6 1.2-31 R-Q31!
demineraliser hoist 1BH220 5 HPCI pump and turbine hoist 1AH211 Reactor 54 1,2-26 w-Valt 1BB211 6 RCIC pump and turbine hoist 10H212 Reactor 54 1.2-26 w-Vill 7 Main steam tunnel underhung crane 10H214 Reactor 102 1.2-28 P-Q311 10H223 8 Inboard MSIV hoist 10H203 Reactor 102 1.2-28 Q-Rill (Drywell) 9 Vacuum breaker valve removal 10H207 Reactor 54 1.2-27 N-V3 1 hoist (Torus) 10 Main steam line relief valve 10H202 Reactor 135-6 1.2-29 HP1944 removal hoist (Drywell) jg 11 Turbine building bridge crane 10H102 Turbine 137 1.2-16 E-r:12 12 reedwater heater removal hoist 1AH103 Turbine 102 1.2-14 E-Eg g l' 1BH103 13 H&V equipment removal hoist 10H104 Turbine 171 1.2-17 H-r:12 14 Motor-generator set hoist OAH105 Turbine 137 1.2.-16 Eu-Ep2 OBH105 T100277tv
BCGS FSAR TABLE 9.1-10 01/86 FY LOAD RANDLING SYSTEMS DATA SUMPUUtY Page 1 of 4 s
Is Ioad Over Max Vert Is Ioad Over Saf ety-Related (5)
Capacity Lift seismic Design Safety-Related(5) Equipement on Exclesion (tons) (ft in) Cat I Standard (2) Equipment? Next Iower Elev Criterio.1fQ 23R 150 main 129-0 Yes a, b Yes Yes None 10 aux 23R 30 16-3 NoI3) c, d No Yes None t-20R 24 12-0 NOI3I c, d Yes Yes None 9-17R 17.3 10 26-0 No d No No B 213 4 9-10 NOI3) c, d Yes NA None ISR 3 9-0 NoI3) c, d Yes NA C 20R 2-1/2 16-0(108214) NoI3) e, dI4I Yes Yes None 108223) 00R 2 16-0 NoI3) d Yes Yes None
.-22R 2 7-0 NoI33 d Yes No C 1 32-2 NoI3) e, d No Yes C
-) 220 72-3 No a, b No No 3 main main 45 122-0 aux aux ,
22 24 12-6 No d NO No B 3 15 37-0 No c, d NO No B 29 15 16-5 NO e, d NO NO B j Amendment 14 G-T j 17R-2cR 36-0 1
r, i
r
~
D i
/'
IK%S F5AS 39/33 tacts 9.5-te temat> Fece 3 et e se sees een Sgetpaeat eles Teet le seed Dees Safety-toletoe Ites Tag Flese Blee Ise Fig Colems Caree tt y Lift Se teele Desige safety-Seleted Sqvtposet en Recluelee ye trene se actet qhmeet totietne tft) gunner keee feeeel tft tal Cet i St endere t al Sp tgeent f test tewee Elee Ce lter nen 39 aystement essententaatten tems Stulle Seretee ene 183 t.3-2e no-s e 39.e-3 3. 9 5 10-3 selgi e,e,e l83 m. m, s hetet eeeeeeee 33 accatae shop endeehung evene CBS399 Sovetco ene 193 1.3-30 so-ense S 11-9 se e, ofil eso e, e ces3et sesseete t 3.4-31.9 MElet (MB 30 t 31 amete eveyeestes eestesenetten 0E3 389 Seestee and le 1.3-10 Be-E s t1.0-19.9 3 9-3 mm837 4, e ens ne e remy hetet CEulte eedomete n -te et. .tet ugt3 .eeuee e.e ., 9. 3-i . e . t .. .- e . . . t 3, w3> .. e - me . l
-in e.coe.to 31 94eeel genetetet sadoetung evene seseeG Centeel and 103 9.3-31 0-es 34.3-34.s e 19-4 meIII e, e, e ses vee mane 105498 eteeen game-SCW499 eeter 995e#
- 3. sm.te eueano ooeur me.e aussee inese stree- i33 f. 3-4 9 a,-c s-e le as we me n. e, . v vee me.
see. In eene mete
, 95 00 *-G*
eos see 31 geseannet neet ettend eeuseet saatte seertes sta I.3-29 P-e e 300-339 IS 33-6 nelII t e, e as Tee ame astet tee 390 3e _ aseemhinee eyeten totet tem 319 Centeen ene GT-3 9.3-84 me-a s 34.6-39. 9 3.leteellet 10-9 um e no et (
98W 310 elemet geme= l.g tese ntet setes
- 3. C. .e.e.ee -let ... seen.e In i.3-n ,-. 39.-n. E., i.i ni f.e .. ,ee e i
.ac. iet ni .eenes On . 3-n e.,t.-n.
.. . , > ,ee ,.e .m.e i
- o. c. .eet -..t. .. . sea. iel s.3-n ,-s,u. iu 330-34.3a is. ni .. ... p .o ve. .moe o,b,d Ot993% Tty amendment la l
} \
HCGS FSAR TABLE 9.1-11 (cont) Page 2 of 2 AUXILIARY TROLLEY Length of trolley travel 132 ft 9 in.
Trolley span 24 ft 0 in.
Trolley weight 39,000 lb Number of wheels 4 Type of wheels Parallel tread l Wheel size 18 in.
Drive motor power 1 hp at 900 rpm Maximum travel speed 50 ft/ min.
Minimum travel speed 15 ft/ min.
Minimum incremental movement 3/8 in.
Number and type of brakes 2 electric disc-type Type of bumpers Polyurethane Type of control ' -
5-step reversing HOISTS Main Auxiliarv 4
Rated lifting capacity 150 tons 10 tons 4
Drum size (pitch diameter) 65.625 in. 26.375 in.
- i Upper sheave size (pitch diameter) 39.5 13 in.
i Lower sheave sizes (pitch diameter) 45 in., 17.in.
39.5 in.
Equalizer sheave size (pitch 39.5 in, None diameter)
- 19.5 in.
Rope type 6x37 IWRC, 6x37 IWRC, i
EIPS, right oil-free regular lay stainless preformed steel, right regular lay, i
preformed
[- Rope diameter 1.5 in. I in.
Reeving type 8 part 2 part Number of reeving systems 2 2 Hoist motor power 60 hp 30 hp Maximum hook speed ft/ min. 35 ft/ min.
Minimum hook speed . ft/ min. ft/ min.
]'
Minimum incremental hook movement 1/32 in. in.
Maximum travel of hook 129 ft 0 in. 129 ft 0 in.
Number and type of load brakes 1 eddy 1 eddy j current-type current-type Number and type of holding brakes 2 magnetic 2 magnetic
. shoe-type shoe-type Type of control Static Static stepless stepless
!k Er] h.7sl
TABLE 9.1-12 (cont) Page 3 of 8 l First Elevation Second Elevation Sa f ety-Pelateil, Safety-Related, 5 Safe Safe Shutdown, Safe Shutdown, Load or Decay Hazard or Decay Hazard Load Lifting Path Heat Removal Elimination Heat Removal Elimiration Beavy. Load weight M ice Fiat *3 Feet Equipment Criterionts) Feet Equipment criterion l
- c. Head strongback 4.4 tons (None 9.1-32 201 RPV d 178 B6F FRVS Recire. d l required) Sht.162 Units l 162 -SIC d l 162 'A' H Recombiner d i 162 -'A' HaO Analyzer d l
- r. Spent fuel 6 tons (None 9.1-32 201 None NA 162 ege H 0, Analyzer d I cask yoke required) Sht. 11 162 -Sir d l 162 -Fuel Pool Pueps d l 6 Heat Exch. l
- c. Hatch cover 2.4 Single- 9.1-32 201 None NA 162 None NA l 4' x 48-6" tons failure proof Sht. 1 l l sling l
- t. Hatch cover 7.5 Single- 9.1-32 201 None NA 162 'B' FRVS Recire. d l 10' x 10' tons failure proof Sht. 1 Unit I sling l
- u. Refueling 10 Single- 9.1-32 201 RPV e 162 ' A' He Recombiner e l bellows quard tons failure proof Sht. 6 162 'A' H2 0, Analyzer- e l ring sling 162 -SLc e l t v. Jib crane 1.6 tons Single- 9.1-32 201 RPV d 178 'F' FPVS Recirc. d l failure proof Sht. 5 Unit l I
sling 162 None NA l tr. Channel handling 0.8 ton (M 9.1-32 201 None NA 178 B6F FRVS Pecire. e l boca crane J. ,}i;:f) Sht. 7 162 Unite
-SIC l
l h .pq 162 -HaO Analyzers e l
_w gg 162 -Ha Pecombiners e 162 -Fuel Pool Pumps e
& Heat Exch.
- x. Dryer-Separator 2 tons (None 9.1-32 201 RPV d 178 -B6F FRVS Recirc. d l sling required) Sht. 12 Units l 162 -SLC d l 162 -He Recombiners d l 162 -H Or Analyzers- d 162 -Fuel Pool Pumps d
& Heat Exch.
Amendment 8 l I
! k TABLE 9.1-13'(cont) Page 6 of.8 l 1.
block, and hook for both the main and auxiliary hoists are i designed to support a static load of 200 percent of the
- design rated load (DRL), instead of the maximum critical i load (MCL) as required by NUREG-0554. For the main hoist, '
} the DRL is 150 tons and the MCL is 130 tons. For the j auxiliary hoist, the DRL is 10 tons and the MCL is 8.5 tons.
! Each load path of each dual path hook was given a 200 t percent. static load test. Geometric configuration
! measurements'of the-hook were made before and after each l test, and were followed by both. volumetric and surface non-i destructive examination. The examination results are documented and recorded.
L (16) Section 4.4 - iven in Table 9.1-11, the maximum main i U hoistsspeed i ft/minfand the maximum auxiliary hoist UEE
} 19'S*N speed is 35 ft/ min.- The " slow" column of Figure 70-6 of CHAA-70 suggests speeds of 5 and 20 ft/ min for the main and
.. auxiliary hoists, respectively. The static stepless
! magnetorque control provides smooth hoist acceleration and 1
deceleration, and precise spotting'of the load. The
, auxiliary hoist speed is only 17 percent above the slow
- speed (30 ft./ min.) recommended for cab operated cranes in i Table 2 of the Whiting Crane Handbook, 4th Edition, and is
!(. well below the recommended medium speed of 60~ft/ min.
(17) Section 4.5 - Dual upper limit switches of diverse' design in
{ series, and an overload cutoff switch on each hoist stop the i hoist motor and set the brakes. Motor overtemperature
- switches activate warning lights in the cab and on the 1 pendant. Each limit switch allows the hoist motor to be
! operated in reverse after it has opened.
1 i (18) Section 4.6 - As described in Section 9.1.5.2.1.2, the main hoist sister hook and lifting eye bolt are independently ;
j supported by their respective crosshead and bearings that
- are in turn suppotted by the load block. The auxiliary hoist hook and shackles are independently supported by the i load block.
(19) Section 4.7 - Side loads are not planned. The main and auxiliary hoist reeving systems do not include wire rope guards. #
)
j (20) Section 4.8 .The main and. auxiliary hoists employ redundant.
- holding brakes. Each brake is coupled to the drum via a j separate gear train.
)
i (21) Section 4.9 - As described in Section 9.1.5.2.1.2, the
! , mechanical holding brakes are automatically activated'on
- ( loss of electric power. The torque rating of each brake is j Amendment 8 i
i
__2 .._,..-..m. ..,_...m. -
. . _ . , - _ , . - , , - _ _ _ . _ _ , , _ _ _ ~ . _ . . . , _ _ _ . . _ _ . . _ , _
^
\ r HCGS FSAR 07/85 Table 9.1-14 (Page 1 of 2)
ROPE CREER SPECIAL _ LIFTING DEVICE PACTORS OF S AFETY Maximum Combined Static Stress ?UREG-0612 l Maximum Lifting Maximum and Design Stress Pect ion 5.1.1 (4)
Rated Load Device Static Dynamic Dynamic Factor Design Factor of capacity Weight Weight Load Load Load vs. Factor vs. Safety
@ Special Lif tinq__ Device tons _ t ons _. _ toms _ tons _ Factort*8 tons Yieldts: UltimmtP(58 _Compli an ce
- 1. Efv head strongback 100 97 0.15 P yest a
- 2. Cryer separator sling 73.5 73.3 0.15 ygg w c a
- 3. RPV service platform sling 7.2 5.9 0.175 by]s 4 fuel cask ycke 110 110 (as ta3 0.15 cas tas (as tas
- 5. Feactor well shield 107.5 107.5 5.5 113 0.15 130.0 6 10 Yest?8 3:1ug sling l
- 6. (CELETED)
- 7. celeted ,
t
- 8. FPV stud tensioner 5.3 5.3 0.2 5.5 0.175 6.5 14.2 14.7 Yestra sling
- 9. Tersonnel air lock 30 30 0.7 30.7 0.15 35.3 2.3 3.9 No l strongback
- 10. Fuel rack lifting 10 10 1.1 11.1 0.175 13.0 6 10 Yes fixture f 11. New fuel inner 3.4 0.97 0.01 0.98 0.175 1.16 11.4 11.9 Yestes bon lifting sling l
- 12. New fuel inner 2.1 0.96 0.01 0.97 0.175 1.14 5.7 6.0 Yes bom tilting sling Notes:
(a3 Deleted (as The spent fuel shipping cask and yoke are not ye known for HCGS. The cask weight and dimensions used for the HCGS design are based on the projectel 125-ton NLI 26/32 rail cask. A 110-ton load is used here to acknowledge ndment it
_ . . _ . _ _ . - . , . . . , _ __.____._.______.._._.______m ___ _ __ . _ . ..__. __. . _ . . , _ _ _ _ _ . . _
g 7 .
'I HCGS TSAR 11/85 l I
i
- Table 9.1-14 (Cont'd) (Paqa 2 of 2)
I j of the NLI cask design responsibility by Nuclear Assurarce Corporatior. (N(C) and subsequent development of the NAC .
12/32 cask te replace the projected NLI cask. 3 t83 Celeted
, (*8 Dynaric load factor = 0.15 5 0.005 (hoist speed, feet per minute) 5 0.50. ,
i *
. *** NUREG-0612, sectio, 5.1.1 (4) requires a f actor of safety of 3 versus yield and 5 versus ultimate strength f or tre '
r I
cornbined 11fting device.
static an$ dynamic load. The static load includes the weight of the load plus the weight of the FpeClal (6 0 ^^- 110:17,; 1 .;r: sill 1 ;;_ ;2 -2 :: c ".r ;in;: - f 11:r- prn! ;;;i lir.c; ct T-- -- C '., 0 2, --m: ;;- ' ".. - ; ;; o ; .]
'Ql l
(*$ The lif ting device satisfies the sirgle-f ailure-proof requirements of NUPEG-0612, Section 5.1.6 (1) (a) .
f l l
[M ACDetGH w UFrs% IEvsCE WA:., BEEN MAS 9At6D To HEGT TNer COGCF- FA't.uR& .7Cco8: GuitsuNEf dJ
} SECrioH 5 l. 6 (8) (a d C F MIR66-Ct!& ly ACCC W WfTH 66 dis 313,!!8,130 AND lM AS APPL) CASEy i THE AT-biltT WER6HT IS KkST~ VET ~ AVAR.ABLF. blSEb kACTCes cf SAF67Y WitL I56 PPol/ft;gD AM 1
TW irinAL WEICM 25 to! cwa 1.
i 1
i ,
)
i J n l ,
1 i
i ;
j '
- I i '!
j -l 1 i I .f i !
4 !
l i .
A 4'
( Table 9.1-22 (Page 1 of 2)
SINGLE-FAILURE-PROOF POLAR CRANE LIFTING DEVICES AND ASSOCIATED l HEAVY LOAD LIFT POINTS Special Single NUREG-0512 Lifting Device / Heavy Load Lifting Failure Applicable Lift Point Device (1) Proof Criteria
- 1. Fuel Cask Yoke Yes Yes Note 2
- Spent Fuel Shipping Cask NA Yes Note 2 4
' t'
- 2. RPV Head Strongback Yes Yes j% e te 7l 5.l.6 (t h )
- Drywell head NA Yes 5.1.6(3)(a)
- RPV head NA Yes 5.1.6(3)(a) l
- RPV head insulation &
frame NA Yes 5.1.6(3)(a)
]( 3. Shield Plug Sling Yes Yes 5.1.6(1)(a)
- Reactor well shield i
plugs NA Yes 5.1.6(3)(a)
- Dryer / Separator pool plugs NA Yes 5.1.6(3)(a) ys q 4. Dryer / Separator Sling Yes Yes a
' c t s " 7. I. 6 ( Va.)
- - Steam dryer NA Yes 5.1.6(3)(a)
J
- Moisture separator NA Yes 5.1.6(3)(a)
[ 5. (DELETED) l V
- 6. Service Platform Sling Yes Yes ";t: : 5'. l. 6 O)(p.)
,/
- Service platform NA Yes ";t; 5.l.6(3I(L)
- 7. Fuel Rack Lifting Fixture Yes Yes 5.1.6(1)(a)
- Spent fuel rack module NA Yes Note 4 l
1
- 8. RPV Stud Tensioner Sling Yes Yes 5.1.6(1)(a)
- RPV stud tensioner NA F.I.6[3IQ) yes
,{
Amendment 12 l 1
- ._ _ _ . _ _ . _ _ _ ___________.____ .__i_ ..m , _ . . , .--
- HCGS FSAR 5/85 Table 9.1-22 (Cont'd) (Page 2 of 2)
Special Single NUREG-C612 Lifting Device / Heavy Load Lifting Failure Applicable
> Lift Point Device (1) Proof Criteria 4 9. Miscellaneous Slings (Note 6) No Yes 5.3.6(1)(b)
Spent fuel pool slot plugs NA Yes 5.1.6(3)(b)
- Spent fuel pool &
cask pool gates NA 5.1.6(3)(a)
- Head stud rack NA [Yes 7 5'. l. 6(32fi)
- Flux monitor shipping Yks crate NA No NA
- 4'x4'-6" Hatch cover NA Yes 5.1.6(3)(a)
- 10'x10' Hatch cover NA Yes 5.1.6(3)(a)
- Refueling bellows guard ring NA No NA
- Jib crane NA Yes 5.1.6(3)(b)
! - CHANmL 4 Anous Yam @#W NA Yss 3. l. 6(3)(Ed
- 10. Polar Crane Main and Auxiliary Hoists Note 5 Yes 5.1.6(2)
- 11. New Fuel Inner Box Lifting Sling Yes Yes 5.1.6(1)(a)
- Inner New Fuel Container NA Yes 5.1.6(3)(a)
Notes:
(1) Special lifting device factors of safety are given in Table 9.1-14. .
(2) The spent fuel shipping cask and yoke are not yet known for HCGS. A single-failure-proof shipping cask lifting device
[u ggng) (yoke) and cask lift point design in accordance witn NUREG-
\ 0612 Sections 5.1.6(1)(a) and 5.1.6(3) will be selected.
(3) Th; lifting d;vic; end/or lift-p; int: Of thi: h: ey 10:e willlF be up;raded-to-meet-the-efngle fai-lue proof guideline; ef -
N'Jn 0 06: 2. Certi== 5.'.5. l (4) The spent fuel rack modules have no lift points. The design of the fuel rack lifting fixture eliminates the need for lift points on the module.
(5) The polar crane main and auxiliary hoists are integral parts of the polar crane and are not considered special lifting devices, t (6) Miscellaneous slings that are not special lifting devices are selected as discussed in FSAR Section 9.1.5.1.n.
l Amendment 10 1
, Table 9.1-23 page 1 of a l POLAR CRANE LOAD DROP ANALYSIS COMP ARISON 4 GAINST MURE3-0612 EVALUATION CRITERI A NUREG-0612 EVALU4 TION CRITERIA &
{ I II III IV FSAR Section Heavy Load Doses Less FR rless no rue r No Loss or for Safety than 255 of than 0.95 Uncovery Safe Shutdown Evaluation 10CFR100 Function
- a. Peactor Well shield Flags (1) (1) (1) (1) 9.1. 5. 3. 2. 3 1 1 4 1
- b. Drywell Head 9.1.5.3.2.2
- c. Peactor vessel ifead
[] [ 9.1.5.3.2.2
, d. Moisture Separator 9.1.5.3.2.4 1 1 1 I e. Steam Dryer g) y y 9.1.5.3.2.4 i
- f. Drver/ Separator Pool Plues (1) (1) (1) (1) 9.1.5.3.2.5 5
- g. Spent Fuel Shipping Cask (2) (2) (2) (2) 9.1.5.3.2.1
.. Auxiliary Heist 1.oad Block (3) (3) (3)
} (3) 9.1.5.3.1
- 1. Main Holst load Block (3) (3) (3) (3) 9.1.5.3.1
- 1. Spent Fuel Pool Slot Plugs (1) (1) (1) (1) 9.1.5.3.2.9
!' k. Spent Fuel Pool Gates and Cask Pool (1) (1) (1) (1) 9.1.5.3.2.9 I Gates 1 1 1 1
- 1. PPV Service Platforsr p p p 9.1.5.3.2.6
- 9. tud Back 9.1.5.1.2.9
, n. Vessel Head Insulation and Frame i p *.1.5.3.2.2 i c. Flux Monitor shipping Crate (9) (9) (9) (1) 9. b5. 3.2.9
- p. Stud Tensioner Frame '
9.1.5.3.2.8
{
- c. Head $troneback Spent Fuel Cask Yoke A [) 9.1.5.3.2.7 I
- r. (2) (2) (2) (2) 9.1. $. 3. 2.1 b *
- o. Hatch Cover 4' x 4 ' - 6" (1) (1) (1) (1) 9.1.5.3.2.9 f
lI =
Amendrient le l
. ,, __. . _ _ _ , _ , _ , . _. _ . _ . . __ _ _ . _ . . . . . _ - , . ~ . _ , . ~ . , , , _ , . . ,, , - . . _ . ,
f p H:'GS TSAR C 7/ tt 5 g Table 9.1-23 (Cont ' d) Pa$e 2 of 4 NtJREC-0512 EVAI,ddION_. CRIMRI A j I II III IV FSAR Sect ion j Heair Load Domes Lese IIdU Lets No Fuel No 1,ons of for Saf rt y than 25E of than 0.95 Uncovery Safe shatdown realuat:nn 10CFR109 Function
- t. Iatch cover 10' t 10' (1) (1) (1) (1) 9. L 5,3. J . e
- e. Refueling Bellows Guard Ring ($) (8) (8) (9) 9.1.5.3.2.9
- v. Jib Creme (1) (1) (Il (1) 9.1. 4.1. 2.9
- 1 1
- w. Channel Beadling Bocs: Crane %
- 1 1 3 p'J) 2 JJ8J) 1 9.1. S . 3. 2.'I n
- x. Dryer-Esparator sling p) p) M p 9.1.5.3,2,4 Y. Scent Fuel Re:E Modules (1) (1) (1) {1) S.1.E.3.2.7
- 2. Tetl Rack Lifting rixture (1) (1) (1) (1) 0.1.5.3.2.7 ca. Eaaetor edell Stile 3d Plug Sling (1) ( 1) (1) (1) 0.1.6.3.2.3 bb. (CE:,ETEC) l cc. New fusel Inner container (11) (11) (11) (i t) 9.1.$.3.2.11 1 12 NC*ES:
(13 The crane, lif ting detice, and lif t points of the heavy load satisfy the eingle-failure-proof g side 11 nee of NUREG-0612, Sectit>n 5.1.6. No load drep analysis is requireJ
- 12) A single-tailure-proof fuel cask lif ting device (yoie) and cask lif t point desig?: in accordance with NOREG-0612 will be selected for RCGS. No load drop analysis is required.
(3) The polar crane and its main hoist load block and aaxiliary hoist load block ' satisfy the einglu-f s11ure-proof guidelines of NUPEG-0612. No load drop analysis is requited.
(4) gW : b::T; 1;;d lef ;;;.:: :nd ::: iebed-444ti 2:rioe- *(li S: ;;:0:2 te riti:f y "- 3;10- Ett icr g c,0 e:ii . : cf Z " = 00t2, S::ti n 5.4,i. O 12 2 d.-- e : :17-17 it yetee4.
l (5) The lift --int: Of the S :'y Ired crc::nt&7 ::tief; t'.- cingle- biler: p ::f 713-Ik- ef " M-?P L -T" 1144a.9
- 73. o i , ma n u ..g w .a - % ro -a-g e <g t..:e p eet ;;i e : f . -
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[W44HM . - Th ' S - el :- ' 53- rirgi: liftin:
-f_t'r--f q M ::: i ri?O irr:Emd fal. "'
p rt. The 52:f-oard-:r? !e net cerr' ' rrer t5^ c; mt "uci pl -
'-i-^=:tir- : = tr;i-; till te
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[hT:D Amendment 11 l W - _ _ _--, _ -- -. . - . - - .e, w - w - -g 3--
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IIC% ITMt 05/85 l
!able 9.1-23 (Cont 'd) Page 3 of 4 l t
'T3Mi- Hft-hd ,hc cu ci we-amedusuwt&oes-Aa -ini-ired. F^ eafetydelet-d. : fe chutder . :: re:y H:t rr c; i ci;- n in ler ted at t" rN149-ilod's- alaua* i aa "l*hia +h- 1 ^2 d P+h Far *ha h==d = tad =c6 - ' p- * "l = t e'-
drag ei tr.: U d :-4 ::d (2A.-4ene' ie met e e-eted te p- -trat- +he -*eal"a edaalina m aa* whi"h ia daaiaaad *^
8 4
aw . ;. the . cavia shuld Thw F 1 t h : W "n d. etc" C:- ;c:: ' c i l i n g i+-nd pt e t ed z e t he-be**y-lea d te i .; ca. eider-e le r-lati"ely light. med the hett ef tt-eefe lin ; ther 6: ete:1 de ting-wt.ir_t -'uld reat=la =ay -^acret- erelliaq Tf la-=$ acacret er=111- ef 'h ech-!;ng - f Mes-w*se re tulated ele ^" vit h !"^'ct =nd d' M " t^ ^^"ip""* =ad piri9 aa *h" ala""*i^^ hel^", rife e w dc = fe:.eti e r m id 'et h- affect-d e e th= q_'!a-aa
- d_ pipir; are -et r quised-for-safe -hutd =n r-ee
- wd.mde.A y e ,; n
- t A cted by tP p :t** Lated 1:2' d:3P-*r" ava ll hlr-- -
y i'
ibe
- t -J-,rasb4s enly car-s4ed-over the "W "^a th- "P" he:d it in plie- The preh-hility of : p;;tekted it a C' 't: E::d 0%ed ::h (e. ? c r s) 10 cer.:idered e-241, and r^uld net f f-^t th e NSr - ri- '""? her d "? "' t^nr1
':nd : :e^ r :se.ser recre!- '16 - d-^p of th- h- M 5+"A r=ch =~'id ha = = 'anad h" = p^=*"1=*ad n ot' h-=d drap fr rhi+ 2 c--^ el Electri- smalveie M cham te t- ace pt"Ie-and r:te the relectie- criteri:-of ""P" -O' %
scet i= 5 L-
' 7t: '5 ' er -^ tha t the al=I :ted teeri^ es-hae feer lif t painte- *
- 72rtelat^^ dr p ef the "a"
-tud (7) [. thace- : 911-r net - trider d likely, ratiefice t " ieur caluati^- e d ite r l = e f ""~- 0 5 ? 2 e : tie- L ' f e r Me-
,J .eneien= e:,_,
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-- - . . m.- .- , ,c,._.
(8) Tta refueling bellows gustJ ring is lif ted by a single-failure-proof niing selected in accordance with NUBEG-0612, i" secticn 5.i.6 (1) (b) . The 10-t on guard ring, if assumed to drop, would dissipate much of the energy through dSf ormation of the circular guard ring. A postulated drop of the refueling bellows guard ring, while not considered 111mly, satisfies the four evaluation criteria of NURra-0612, Section 5.1 for the easte reasoning as discusstd 10 (Mte (6).
(h W flus monitoring shipping crate is lifted by a ningle-f ailure-proof sling selected in accordance with NUREG-0412 Sec+ 1on 5.1.6 (1) (5) . Administrative controls will be used to ensure the lift height above the yefueling floor ta minimized. No safety related, safe shutcown, or decay heat removal equipnent is located at the refueling floor elevatien within the load rath for the shipping crate. The flux monitor shipping crate le not carrie3 over the spent fuel pool Cr PP7.
A portulated drop of the shipping crate (2. 5 Leia) is not expec 9 d to penetrate the massive refueling floor which i in Jeelaned to supNrt the heaviet shield plugs, f,001 plugs, RPV head, etc. Concrete spalling is not expected as l the heavv lotd being censidered is relatively light, and the bottom of the refueling floor is steel decking which I would contain any concee*e spallinS. If local concrate spalling of the refueling floor were postulated along with
/ impact and dama*:e to eqaipment ed piping on the elevation below, safe shutdown functions would not be affected an !
the equipment arid piping ate not te]uired for Psf e shutdown, or redanda'nt systems not af fected by the (,vtulated '
/ 1%d drop are availabit in rummary. an analysis of a postulated drop of the flux monitor shipping crate demonstrates that the four
) evaluation triteria of FUREG-0612, Section $.1 are saticfied.
l l, _ . -
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Amendment 10 l
HCGS FSAR 1/8C of 700F to 1040F. Aa electrical resistance heater system l provides a backup heat sourcs that maletains thE solution temperature at 750F (automatic operation) to 85cf (automatic shutoff) to prevent prepipitatton of the sodium pentaborate iror the solution during storuge. High or lov borop solutton temperature (in either the tank or the pump suction piping), or high or low liquid level in the tank, is anounciated in the main control room. Discussion of the baron solution storage tank level instrumentaticn is provided in Gectior. 7.A.1, Each positive-displacement injection pump is cited to inject the boron solution into the reacroe at the rate of 43 gpm. The pump and system design pressure between the explocive-actuated valves and the pump discharoe is_1400 psig M.79 ttie pump discharge lines are setLNume{vo
'P9relief 14 00valves poiq. in To prevent bypass flow from one puYp in case of relief valve failure in the line from the other pump, a check valve ir ir,stolled downstream of each relief valve line in the pu7p distbarge pipe.
The two explosive-actuated injection volves in the pump discharge lines provide assurance of opening when needed and enpute that g boron solution does not leak into the reactor, even when the pumps are being tested.
Each explosive-actuated valve is closCS by a plug in the volve inlet chamber. The plug is circamstribed with a deep groove so the end readily shearc off when purbed with the valve shearing plunger. This opens the inlet hole thrcugh the plug. The sheared end is pushed out of the way in the chamberi it is shaped so it does not block the pcrts after release.
The shearing plunger is actuated by an . explosive charge, with dual ignition primers inserted in the side cbseoer of the volve.
Ignition circuit continuity is centinuously nonitored by a trickle current, and an alare occurs in the nain control room if either circuit opens. Indicator lights in the nain control room show which primer circuit has oIened, e
V 9.3-19 Amendment 4
j HCGS FSAR 11/05 (s With the storage tank outlet valve and the maintenance valve downstream of the explosive valve closed, and with the valves on tne test tank discharge and return lines opened, domineralized ,
water can be circulated by locally starting cne of the pumps.
This tett can be accomplished on one loop during normal plant oporation while the remaining loop is available to inject control 11guld in response to an initiation signal.
During a refueling or maintenance outage, both pumps and putsmatic valves can be tested. In the test mode, demineralized water is pumped from the test tuns through the explosive valves an9 into the vessel upon receipt of a simulated ATW3 signal from '
the RRCS logic. During testing, the storage tank outlet velve is closed while the test tank disenerge valve is open.
4 i
A:ter functional testing, the iniection valve chear plugs and explosivo charges are replace 6 and all the valves returned to thetr norr.a1 positions, as indicated on Figure 9,3-B. {
t After closing a local locked-opon valve to the reactor, leakage through the in]cction check valves can be detected by cpening the
! valves in the test connection between the containment isolation i
('
injection chec.k valves. Position indicator lights in the main control room indicate that the local valve is e2ther closed fo; teste, or open and ready for operation. Leakage from the reactor through the first check valve can be detected by opening the same test connection in the line between the containment isolation '
iniection check valves when the reactor is prescurized. >
1 Should the boron solution ever be injected into the reactor, either intentionally or inadvertently, then after making certain that the normal coactivity controls will keep the reactor { .
suberitical, the boron is removed from the reactor coolant system i by flushing for grost dilution followed by operating the PWCU system. There is practically no effect on reactor operationc
- when the boron concentration is below approximately 50 ppm.
The concentration of the sodium pentaborate in the solution tank is determined periodicelly by chemical analysis.
V Electrical supplicsind r G+eJ- M yee are also subjected to periodic testing, as discussed in:K.'.t;te? T". ,
)
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FIGURE 9.3 8 Amendmet 12,09/95
(
This inspection consists of visual, surface, and volumetric examinations, as follows:
- 1. When critical areas of the unit are exposed during
, inspections, they are nondestructively tested by ultrasonic testing, magnetic-particle testing, liquid penetrant, or eddy-current testing, and
- receive a ccmplete visual inspection. In some cases, more than one method is used to ensure the integrity of the piece. Those areas normally ,
tested include, but are not limited to, the rotors, wheel bores, keyways, bucket dovetails, pins of finger-type dovetails, bearing journals, '
I couplings, coupling bolts, nozzle blocks, i diaphragms, buckets, valve steams, valves, and
- pins. These inspections will be conducted at I approximately 10-year intervals. r j
I b. The main stop valves, control valves, and combined intermediate valves are inspected and nondestructively tested at a frequency based upon their operation, operational tests, industry experience, and good industry practices. Critical areas such as the valve
",( stem, seats, valves, bushings, and casings receive an ultrasonic test, liquid penetrant test, or magnetic-particle test, and a thorough visual inspection. At least one valve of each type will be dismantled for inspection at approximately 3-1/3-year intervals. If l unacceptable flaws or excessive corrosion are found in ,
a valve, all valves of its type are inspected. Valve bushings are inspected and cleaned, and bore diameters i are checked for proper clearance. :
. c. Main stop and combined intermediate valves are [
exercised at least once a week by closing each valve i and obcerving by the valve position indicator that it !
moves smoothly to a fully closed position. High !
pressure turblr.e cor. trol valves are exercised at least l once a mon'ch through at least one complete cycle from i the running position.%s l W ot4R Wt.yc rvvnc+) C VMCED BY 10.2,4 SAFETY EVALUATION tywur,w; vAu/s Tecmo) hcArea.
j
! The turbine-generator has no nafety*related function. Failure of 1 th& system does not compromise any safety-related system or ;
i [, component or prevent a safe shutdown of the plant.
I\-
l 1 10.2-13 Amendment 13 e o
e
- k. TABLE 13.1-la (cont) Page 36 of 71 l
- 2RCO!!!! L ATTAIRCj MANAGER - PERSONNEL AND ADMINISTRATION h
i TO BE PROVIDEDolFRIOR TO 7'JEL LOA-[
^
LOI9J TCSfTIC+) IS FKLED i
By A WRHAww PSE(6 EmPtDVEE f
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Amendment 14 l 4___ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . - _ - _ _ _ - _ _ _ _ _ - - _ - _ _ _ . . .
.. = _.._ . _ . . _ . . ._.._ ._. . ___. .. __ _ . . _ _ _ . . _ _ _ _ .
i
, (%) TABLE 13.1-la (cont) Page 65 of.71 l '
4 MANAGER - PROJECT INSTALLATION 1
2 A
i I mA me nnatatMen hnTAM MA et IPT TA&M I
{ f& V w em E sT%# Y & M4m W E n 4 g#n av 4 w meed wnw 3
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Amendment 14 l i
l
Page 65a cf 71 a
A Manager - Project Installation NAME: Eugene W. Barradale EDUCATION: '
1942-1946 Columbia High School, South Orange, New Jersey 1961 Rutgers University College, Bachelor of Science, Accounting 1962-1964 Newark College of . Engineering, Engineering
- Math, Computers & Application 1965 Patent Law for Engineers, IEEE 1966 Non-Destructive Testing of Weldments, i AWS 1967 Monmouth College, Physics 1967 Westinghouse Power Reactor and Nuclear Systems Design and Functions 1967-1968 ASME/IEEE Introduction to and Elements of Nuclear Engineering 1970 IEEE, Engineering Economics ~
1972 PSE&G, Supervisory Training P:hgram 1975 AMA, Project Management, Planning and Control 1979 PSE&G, Management Training Program 1980 PSE&G, Advance Management Programc 1981 PSE&G, Improvdd Managerial Effectihenecs, Communication' Techniques (SAI) l l
l l
0 ,N
p Page 65b of 71 EDUCATION:
1 '1981 PSE&G, Interviewing Techniques 1981 Quality Assurance Orientation 1983 PSE&G, Team Development Techniques 1984 INPO, Managed Maintenance Seminar 1986 Abney Associates, Management by Objectives,
.] Performance Planning i EXPERIENCE:
1985-Present Manager - Project Installation Services Division - Nuclear Engineering Department i
i Responsible for installation of major j modifications at Salem and Hope Creek i Generating Stations. Directing work of staff and contracted forces for
- planning, cost control, installation j testing and problem resolution in support j of operating plants. Responsible for j construction completion and contract 1
management at Hope Creek.
1981-1985 Manager - Nuclear Construction Support -
Nuclear Services' Department
-l
)
1 Responsible for plant betterment and l maintenance for installation of modifications 2
and maintenance support work at Salem Generating Station. Directing work of staff and major contractors.
1976-1981 Project Construction Manager-Engineering and Construction Department
, Responsible for construction, testing 4
and turnover to operations of Salem No. 2. Responsible for support of Salem No. 1 maintenance work plus all major modifications and TMI changes.
i
L k
Page 65c of 71 EXPERIENCE:
1974-1976 Senior Construction Engineer / Site Manager -
Engineering and Construction Department
. Resident Senior Engineer at Hope Creek Generating Station. Initiated the project with Bechtel Power Company and established field construction programs including administration, construction, security, safety and contract methods.
1971-1974 Construction Engineer / Senior Construction Engineer Field assigned to new construction department to manage the construction of Salem Generating Station. Responsible for planning, scheduling, cost, material and manpower control, plus various field supervisory assignments.
1967-1971 Associate Engineer / Assistant to Project Manager - Electric Engineering Department Develop methods and systems to initiate and control design, purchasing, costs, schedules and field construction for Salem Generating Station. Monitor and expedite design and procurement, make weekly field trips to construction site, interface with construction and engineering for problem identification and resolution.
1956-1971 Assistant Engineer - Mechanical Engineering Division Design, procurement and construction monitoring of piping, hangers, supports and mechanical components for nine major fossil units and gas; turbine installations.
e s
V
Page 65d of 71 EXPERIENCE:
1954-1956 ' Engineering Assistant - Cost Engineering.
Performed generating station cost unitization,
' insurance valuation and budget analysis for new.and operating fossil generating stations.
1950-1954 Authorization Bookkeeper
] Recovered construction costs for relocating company facilities for the New Jersey Turnpike Authority and the New Jersey Garden State Parkway Authority.
1948-1950 Lineman - Transmission and D'istribution Department-
, Installed and upgraded distribution facilities.
1946-1948 U.S. Navy - Service School and Fleet Servica i
f i
i i ,
j -.
HCGS FSAR 1/86 l TABLE 13 1-4 (cont) Page 96 of 123 l SENIOR NUCLEAR MAINTENANCE SUPERVISOR - I&C l RESUME WILL BE FROVIDEC PRIOR TO FUEL LO #
WSeer THE D=SurE a= Ebsti C. Rustt , El i
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Amendment 14. l
Page 96a of 123
, SENIOR NUCLEAR MAINTENANCE SUPERVISOR - I&C NAME: Edison C. Rush II EDUCATION:
1986 Wilmington College, Wilmington, Delaware.
Working toward a BS in Business Management with completed course work in Accounting, Business Law, Principles of Management
- and' Advanced Communication Skills.
Currently classified a senior.
8/79-8/80 Salem Community College, Penns Grove, New Jersey. Associate Degree in Electronics /
Instrumentation and Computer Technology with course work in Calculus, Process d
Controls, Computer Programming and Digital Techniques.
1 5/75-10/75 SlW Nuclear Submarine Prototype, Idaho Falls, Idaho. Training in Nuclear Reactor Plant and Steam Plant Operations 2
and Maintenance, and Radiological Controls, 9/74-4/75 U.S. Naval Nuclear Power School, Mare j~
Island, California. Nuclear Physics, Reactor Theory, Thermodynamics, Water Chemistry, Fluidics, Reactor Plant and Steam Plant Technology, Electric Plant Distribution, Metallurgy, and
- Health Physics.
9/73-5/74 Naval Electronics Technician Senool, Treasure Island, California. Phase
- 1,2 and 3 i
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Page 96b of 123 EXPERIENCE:
8/79-Present Public Service Electric and Gas Company 1/86-Present Senior Nuclear Maintenance Supervisor-I&C - Hope Creek Operations Responsible for instrumentation and control systems maintenance, testing and calibration.
2/81-12/85 Instrumentation and Controls Associate Engineer - Salem Nuclear Station Supervised bargaining unit personnel in the repair, calibration and maintenance of nuclear power plant instrumentation and controls. Performed these supervisory duties in a training capacity for Instrument Supervisor position. Supervisor responsible for Unit 1 radiation monitoring instrumentation and control system.
8/79-1/81 Instrumentation and Controls Technician -
Salem Nuclear Station Performed repair, calibration and maintenance on nuclear plant instrumentation and controls. Qualified to perform maintenance on the reactor protection system and radiation monitoring system.
9,;3-8/79 U.S. Navy 11/75-8/79 Nuclear Power Program, Reactor Controls Division Leading Petty Officer, ETl(SS)
Supervised Nuclear Reactor Operators in the safe operation and maintenance of the nuclear reactor plant. Insured the proper operation and maintenance of all reactor plant instrumentation and control systems.
9/73-11/75 Various training and schools detailed above.
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Review of the safety evaluations that have been
, completed under the provisions of 10 CFR 50.59.
- f. Review of all violations of the Technical Specifications, including the preparation and forwarding of reports covering evaluation and recommendations to prevent recurrence, to the Vice President - Nuclear and to the General Manager -
Nuclear Safety Review.
- g. Review of all REPORTABLE EVENTS.
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- h. Review of facility operations to detect potential nuclear safety hazards.
i 1. Performance of special reviews, investigations, or i analyses and reporting thereon, as requestad. by the Ganeral Manager - Hope Creek Operations or the General Manager - Nucatur Safety Review.
- j. Review of the Emergency Plan and implerenting procedures including revisions.
, k. Review of-the Security Plan and implementing procedures including revisions.
l 1. Review of the Fire Protection Program and implementing procedures.
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- m. Review of all unplanned on-site releases of -
radioactivity to the environs including the preparation of reports covering evaluation, recommendaticro, and disposition of the corrective action to prevent recurrence and the forwarding of these reports to the Vice President - Nuclear and to the General Manager -
Nuclear Safety Review.
- n. Review of changes to the PROCESS CONTROL MANUAL and the OFF-SITE DOSE CALCULATION MANUAL 13.4.1.4 SORC Review Process MD 7HE kADWA3RT ~
TesameJr Svasms.
13.4-4 Amendment 14
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9 09/85 APPENDIX 13L PROCEDURES GENERATION PACKAGE FOR THE HOPE CREEK GENERATING STATION l
PUBLIC SERVICE ELECTRIC AND GAS COMPANY e
e Ru.m 2 ;; . n0;;
Y Revision 2.
13L-1 Amendment 12
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- 6J 09/85
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TABLE OF CONTENTS P
Page ?
1.0 INTRODUCTION
Purpose..........................................
13L-4 1.1 Scope............................................
1.3 Background.......................................
13L-6 2.0 PLANT-SPECIFIC TECHNICAL GUIDELINES...................
2.1 General..........................................
13L-6 -
1 Description of Conversion Methodology............ 13L-6 2.2 a
2.2.1 BWROG-EPG to P-STG........................ 13L-6 !
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2.2.2 P-STG to EOP.............................. 13L-7 I
3.0 FLOWCHARTS............................................
13L-10 3.1 Utilization of Flowcharts........................ 13L-10 ( '-
13L-11 4.0 EOPS WRITER'S GUIDE...................................
4.1 General.......................................... 13L-11 13L-ll 4.2 Document Description.............................
13L-12 5.0 EOP VERIFICATION PROGRAM..............................
13L-12 5.1 General..........................................
5.2 Ve rif ication Program Description. . . . . . . . . . . . . . . 13L-12 EOP VALIDATION PROGRAM................................
13L-13 6.0 13L-13 6.1. General..........................................
Validation Program Description................... 13L-13 6.2
- 32. Rouacaner Coareot ,
3.5 VMAez EscuTica n 13L-2 M
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%mendment
'09/85 3.0 FLOWCHARTS 3.1 Utilization of Flowcharts Flowcharts are utilized for the Operator Action Steps of the Hope Creek EOPs. These flowcharts provide the operator with visible guidance, which will help the operators place the plant into a safe condition quickly and consistently.
The major deficicncies of event-type EOP's are (1) they required the operator to diagnose the specific event in order to mitigate the consequences of that event and, (2) they did not address multiple failures or unavailability of various equipment.
The Hope Creek EOPs will be designed to minimize these deficiencies. This will be accomplished by selecting entry conditions to the EO? which are indications of potential emergency conditiocs or conditions which, if not corrected, could degrade into an emergency. This gets the operator into the EOF quickly. Once the EOP is entered, the order of priority is established by the values and trends of the monitored parameters as the ,
operator executes the procedures.
There is no need for the operator to attempt to memorize the Operator Action Steps because they are visible on the flowcharts which are to be placed in the Control Room.
If an entry condition occurs the operator enters and executes the EOP(s), the operator may exit the EOP(s) by clearing all the entry conditions for that procedure, or by a step within the EOP directing the operator to another procedure.
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f 13L-10 Amendment 12
INSERT FOR PAGE 13L-10 3.2 Flowchart Control The 8 " x 11" portion of the EOPs (Sections 1 thru 4) and the EOP support procedures (300 series) shall be located in the procedure binders, along with the rest of the Control Room operating procedures.
The flowchart location, due to their size and use, requires additional control. Although relocation of the flowcharts due to revision or administrative controls is allowed within the Control Room, the following guidelines shall be followed regarding the location and control of the flowcharts:
o The flowcharts can either be stored or displayed.
In either case, they shall remain together as a set. Examples of acceptable storage locations are a flowchart box or drafting table with a storage rack underneath the table; display examples include the top-back of the Control Console (10C651) or Operators Console (10C649). All of the flowcharts need not be displayed, those not displayed can be stored in a rack at the end of either panel. Strip magnets can aid in the stability of displayed procedures. In no case shall the location of the flowcharts obstruct any displays or controls during their storage use.
o The flowchart location shall provide'for easy access when required. Although the title block provides a quick and easy method of identifying the procedure by title and by number, additional identification methods may be used. Sequentially numbered storage slots or numbered tabs are examples of acceptable methods of identification.
3.3 Flowchart Execution When the need arises to enter and execute the EOPs, a Senior Reactor Operator licensed individual, normally the Nuclear Shift Supervisor, will use the flowcharts to direct the operation of the licensed Reactor Operators in the Control Room, and non-licensed support. personnel and field operators. System operations should be in accordance with approved System Operating Procedures or EOP support procedures.
09/85 o Need for symptom oriented procedures as opposed to event oriented procedures o Entry conditions and exit criteria o Use of flowcharts for operator actions 7.3.3 Discussion of EOP flowchart development from the BWR Guidelines through the use of the Plant .
Specific Technical Guidelines.
7.3.4 Understanding of the content and use of each EOP. This will include careful review and walk-through of procedure steps to ensure operator knowledge of technical bases, location of instrumentation, and use of the procedures.
7.3.5 Successful performance of a series of dynamic, practical exercises using the Hope Creek Generating Station's plant-referenced simulator to satisfactorily exercise each appropriate EOP.
7.4 Training Methods and Evaluation Prior to implementation of the EOP's, operator training will be conducted using classroom discussion and/or simulator exercises, r
jg, i 7.4.1 Classroom discussions will be utilized to gagsgo { provide \ operators with instruction on the f ull complement of EOP's. The discussions will include a careful review and walk-through of procedure steps to ensure operator knowledge of:
o Technical basis for the procedural steps o Location of instrumentation
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o Procedural use and philosophy behind the procedures o Procedural interrelationships o Flowchart use o Procedures which cannot be exercised on the simulator n.
13L-16 Amendment 12
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(' Upon completion of classroom training, the operator's knowledge of the procedures will be evaluated via written examination.
AM. 1 7.4.2 Simulator exercises will be used to reinforce LEG #Eb t classroom training and to provideg operators with practical experience in utilizing and executing appropriate-procedures as a shift (crew). This training will also serve to .
develop the operator's understanding of their responsibilities (roles) during an event and to develop their ability to work together as a team. A wide variety of scenarios will be used, including multiple (simultaneous and sequential) f ailures.
After training, the operator's knowledge of and performance using the EOP's will be evaluated.
Included in this evaluation will be an assessment of the operator's knowledge of their responsibilites (roles) during an event and their ability to ef fectively work together as a team.
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7.4.3 Requalification Training
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All licensed operators will participate in control room walk-throughs using the EOP's during requalification training. The walk-throughs will be conducted in the control room or using the plant-specific simulator.
The training and operations staffs will participate in presenting requalification training. Participants in the requalification training program will critique the EOP's exercised during the training program. Any additional training needs will be determined from this critique and formal feedback discussed in 7.4.5.
13L-17 Amendment 12 l 7 . . . - _~ .--. . . . . . . . . . _ _ . _ - _ -
- 4. Radwaste pressure with respect to outside ambient C
is negative with the system in operation.
- 5. Fan operating capacity is as specified by Table 9.4-10.
- 6. Balancing of air flows and exhaust filtration and adsorption unit testing has been completed. The filtration and adsorption unit testing has met the pgggg'i recommendations of NRC Regulatory Guide 1.140, WM4rr cr.dcrc:03 ANSI N510-1980, including:
4 (a) Visual inspection.
(b) Air flow distribution test.
(c) DOP test for HEPA filters.
(d) Carbon adsorber leak test with halogenated ,'
hydrocarbon refrigerant. '
14.2.12.1.18 GJ-Control Area Chilled Water
- a. Objective
- 1. The test objective is to demonstrate the capability of the chilled water system to supply
_ and maintain the appropriate water temperatures within design specifications.
- 2. Instrumentation, alarms, and annunciators shall function in accordance with the system electrical schematics.
- b. Prerequisites
- 1. All permanently installed equipment, relays, and instrumentation have been functionally operated and calibrated. ,
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14.2-58 Amendment 12 La -
- 5. The main control room shall be maintained at a positive pressure, with respect to surrounding areas, as specified in Section 6.4.
- 6. Main control room air shall be maintained within the limits specified in Section 6.4.
- 7. Balancing of airflows and exhaust filtration and adsorption unit testing has been completed. The filtration'and adsorption unit test shall have met the recommendations of NRC Regulatory Guide 1.140, gggg', EWnicn enuerses% ANSI N510-1980, including:
b (a) Visual inspection (b) Air flow distribution test 1
(c) DOP test for HEPA filters .,
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(d) Carbon adsorber leak test with halogenated
, hydrocarbon refrigerant.
14.2.12.1.20 GL-Service Area HVAC
- a. Objective
- 1. The test objective is to demonstrate the capability of the service area heating, ventilation, and air conditioning (HVAC) systems.
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- 2. Instrumentation, alarms, and annunciators shall function in accordance with the system electrical schematics.
- b. Prerequisites i
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14.2-62 Amendment 12
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- 3. The vacuum relief system is verified to perform according to design specifications.
- 4. The hydrogen'recombiner system is verified to perform according to design specifications.
6, Containment isolation valve operability is checked.
- d. Acceptance Criteria
- 1. All controls, logic, and interlocks function as specified by the system electrical schematics.
l Ten St nm (, '?.r.o.y mdl
- 2. The Hydrogen Recombiner System operation istas specified below:
(a) Upon startup, each recombiner will increase the temperature of the process gas to it's design value.
(b) Each recombiner can be heated up to operating temperature within the design specified time.
(c) The recombiner effluent is cooled to its' design temperature.
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- 3. The Nitrogen Vaporizer System operation is o as follows:
(a) Supplies nitrogen at a rate at least equal to the minimum design flow during makeup.
(b) Supplies nitorgen at a rate at least equal to the minimum design flow during inerting.
14.2-68 Amendment 13 a , - .- _ . - . - - . -._ . . - .
(c) Supplies nitrogen at design temperatures. l wtt Setmera 4 2525 mD l
- 4. TheCombustibleGasAnalyzeroperationishas specified below:
(a) The Combustible Gas Analyzer can sample for H, and 0, from the required locations.
(b) Combustible Gas Analyzer Sample lines isolation valves operate per system design logic.
(c) The Combustible Gas Analyzer can accurately.
sample H, and 0,.
(d) The analyzer sample stream identifier will indicate the sample stream selected when only one stream is selected. When more than one stream is selected, the stream identifier
( will not indicate.
(e) The sample lines are heat traced and maintain required sample gas temperature.
- 5. Containment. isolation valves closure times are as specified in FSAR Table 6.2-16.
- 6. The Suppression Chamber to the Reactor Building and Drywell to Suppression Chamber vacuum relief valves (VRV) functiongas specified below.
Ipat Erenew AJ5.2.3 MDTE DsgN buTmMDWNWN D3-@l (a) The Reactor Building'to Suppression Char.ber VRV isolation valves will fully open within the design specified time when the accumulator tanks are at design specified value while isolated from their compressed air supply.
- (b) The Reactor Building to Suppression Chamber and Drywell to Suppression Chamber VRV will 14.2-68a Amendment 13
) 4. Demonstrate the operation of the cooling coils in the recirculation units to limit temperatures during reactor building isolation.
- 5. Demonstrate the operation of the moisture separater and heating coils in each unit to reduce the relative humidity to acceptable levels prior to entering the charcoal filters.
- d. Acceptance Criteria
- 1. Fans, dampers, iso.lation valves, permissives, interlocks, and controls shall function in accordance with system electrical schematics.
- 2. Filter train trips, permissives, interlocks, and controls shall function in accordance wi,th the ,
system electrical schematics. ,
- 3. System dampers and valves shall isolate within the [
operating times specified in Section 944.2.
- 4. The reactor building shall be maintained at a slightly negative pressure with respect to outside ,
atmospheric pressure, as specified in Section 6.8.
- 5. Systems, unit heaters, coolers, and moisture separation equipment is demonstrated'to operate in '
accordance with the manufacturer's technical i instruction manual. >
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- 6. Balancing of airflows, and exhaust filtration and '
adsorption unit testing has been completed, The '
filtration and adsorption unit test shall have met lusWGi
, t ie recommendations of NRC Regulatory Guide 1,140, a
...._. - "-- - ^*NSI N510-1980, including: ' #
,6 '
(a) Visual inspection :
i (b) Air flow distribution test sm~
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- 2. A13 rme stiall function in accordance with G. E. k '
Preoperational test Specifications.
b, PrGrequisites
- 1. All permanently installed equipment, relays, and instrument.ation h6ve oesn functionally cperated and calibrated,
- 2. Computer diagnoptic tests have been completed and -
test programs loaded.
3T. stis4&svatgpis pgeti;ml]
- c. Test M9thod j
- 1. All red. blocks, including refueling blocks,
.alarme, and interlocks for al) codes of the ;
reactor code switch are checked. ,
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- 2. Rod positicn information system interface process corputer is checked.
- 3. Red notion-directional control valve scquence ic .
checked. -!
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- 4. With simulated Icw powe.r and the rod sequence '
control system bypassed, the rod worth r.intmiget is chscked, -
- 5. With the rod worth minimizer bypassed, the rod sequence control system is checked, 1
- d. Acceptance Criteria
- 1. Rod blocks, and inter 3ocks function as specified j in the GE preoperational test specification. ,
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ks- 2. All containinent iso.la'tf on valve.c ahd othet-
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equipment that. charts or stops automatically uppa recel,ot of a ecctcinmen?. , isolation signa'l mupt be e.pGraole und in trieir untripped po'sition.
- c. Test Method :
- 1. The isolation valves are checked to en.sure that automatic c16sure times are within design requirements by i'aserting simulated signalc and measuring the closure times.
- 2. All logic ecmbinations initiating automatic closure are verified.
- 3. Apri3iary actions, including fan starts, and {
damper action are checked.
- d. Acceptance Criteria
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- 1. Contain.nent isolation valves shal! close automatigally upon receipt of their isolation
( signals.
- 2. Valve closure times shall'be within the requirenents of Table 6.2r46.
~3 , On removal of actuating cignal (ESF) and/or resettir.g of the isolation or actuaticn signal, equipment remains in emergency code.
- 4. Interlocks shall function -in accordance with tho 'l system electrical schematics. -
14.2.12.5.46 $P-Process Radiation Monitoring
- a. Objective
- 1. The test. objective is to verify the capability of the procesa radiation monitoring systen to detect radioactivity in ene monitored process lir.es.
2 h. wim 7xT w IM unM 1GMn Ad$ uJeH';Wc >ntXnu5 34.2-107 Amendment 12 l
HCGS FEAR GT/86 b,
- 2. Demonstrate the- ability.of filters to be
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precoated, backwashbd, recirculated, and placed in
' normal operation.
- 3. Demonstrat0 the ability to transfer s911dr to the solid radwaste system af ter the RWOU phase i
separators have been decantedr using representative waste streceu.
- 4. Demonstrate that the filters and demineralizers produce acceptable water quality, usitg representative waste str.erms.
- 5. Demonstrate flow capacities and flow paths of
- liquid radvaste components and subsystems.
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- 6. Demonstrate the isolution feature 9 of the waste stream in conjunction with the process radiation k sonitoring system. .
- 7. Demonstrate that the evaporators concentrate s represer.tative wacte streams at the rate specified by GE. }
- d. Acceptance Criteria ,
gg ,,g gy m
- 1. Flow capacities of pumpshce csr.ej.;ita t bith e y ,Jreied velud5!11sted in Chapter 11, Tao' le 11.2 -14.
- 2. Controls, logic, and interlecks, function as specified by the system e.lectrical schemati:5 '
- 3. Containment isolation valve closi.ng time is as specified in Table 6.2-16.
- 4. Filter and deminera!Azer precoat and backwasC performance is as specified in the vendor technical instruction manual. ,
- 5. Waste demineralizer effluent quality .is as specified in the GE preoperational test specification.
- 6. The liquid radeaste syster. isolates as specified by the systen electrical schematics and Section 11.5. <
14.2-132 Amendeent 14 L _ _
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- 5. A1:1' applicable instrumentation has been calibrated. ,
c, Test Method j T. Cbeck all controls, interlocks, and logic, j associated with containment instrument gas. '
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l 2. Check compressor operation, including '
j unloadin g/]oadi~ng cycles ' for. lead / lag compressors. ,
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- 3. Demonstrate that the system can provide dry, oil-j free gas.
) 4. Detonstrate that the system.can-provide. compressed-j gas to main steam SRVs, main steam MSIVs, TIP :
drive mechanists, drywell/ suppression chamber i vacune breakers, nain steam sealing system, and ,
other gas operated valves inside containment. '
J 3. Demonstrate that plant instrument air can be lined
! up to the containment ibstrument gas Gystem-from a 1 i< reoote locat.'.on, il l N
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- d. Acceptance Criteria
?. ccntrols, interlocks, and logic, function as specified in the system electrical scr.ematics.
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'4 i 2, The containment instrument gas.ccspressor provides
! compressed air with a 20 sefm capacity as ;
specif[ed in the Leofgn Installation and Test i
Epec.ifidation D3.(It as the dryer nominal capacity. i i } AnD TA6ls 9.5&pr44 2.cs 3 i
- 3. The dryer and filter efficiency is as specified im Section 9.3, Table 9.3-6 as determir.ed by measurecent to meet the critecia of ANSI MC 11.1-1975, i i l
4, The containxent instrument. gas system can provide compressed gas to the components stated in j
i Secrjon 9.3,6 as evidecced by the ability to !
increase'the-receiver pressure from 25 to 85 psig i I 1M 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or less wtah the discharge valve
} ('"
1 closed.
! i j 14.2-335 Atendment 13 i
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- 5. PBV5 isolates oa high containment prossure, wnu aqwm ranetor water low level 2, and high building in a nDTfL ' radJption signal.
M bcrebt 96j 6. The RBVS can maintain % negative pressure cEica F A tn: :Trden-:nd mi leum siGww-etatbd ir-
- K Mh 3 . ', ?-- 2 n . ,_
- 7. Eqt:ip.wnt area unit coolers will remove design i heat Icads (RHR, core spray, HPCI, RCIC, SACS, cteam tunnel).
- 8. Eclancing of sit flows and exhaust ifltration end adsorption unit testing has been completed. The filtration and adsorption unit test shall have mat the recommendations of Regula tory Guide 1.140 luW1 - - - - -- - _ "~^M@ ANSI N 510- 19 8 0.
l 14.2.12.1.69 Condensate Storage and Transfer ,
- a. Objectivas
- 1. To verify the condensate transfer system can provide water to the refueling floor subsystEns such as the reactor cavity and dryer / separator storage pool.
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- 2. To verify the operation of the condensate transfer pumps and ]ockey pumps.
- 3. The condensate storage trak as a source to HPCI and RCIC is verified in the HPCI and RCIC preoperational tests.
- 4. Alares shall function .in accordance with the i systen electrical schematics. '
b, Prerequisites
- 1. All peraanently installed equipment and instrumentation has been functionally checked and calibrated, i 2, AC power is available.
- 3. De;nineralleed water is available to fill the condensate storage tank.
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14.2-144 Amendment 13 I
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- 4. Verification of flow paths to be accomplished I during system flush.
- c. Tes t Method
- i. 710b pathr hw--all -6dec-of-operafi^n arc--checEedl l py;el--thes@4cwPthc--4441-w.~ , . em be verified dusig 4 -
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1,J . Valve logic and valve operating times are enecked.
1 r, Logic, and interlocks are checked. {
3 (. Pump perfornance is checked.
- d. Acceptance Criteria l
- 1. Logic, and interlocks function as specified in the system electrical schematics.
- 2. Pump perforconce is comparable to the head flow
. curves specified in the vendor technical instruction manual.
(V 14.2.T2.1.70 Steam Extraction and Feedwater Heater and Drains i
- a. Objectives 1 To verify the operation of the exttaction non-return check valves.
- 2. To verify the operation of the Icw and high pressure hester level control system.
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- 3. 'Io verify the integrated logic associated with a ,
turbine tedp signal. '
'o . Prerequisites
- 1. Instrument calibraticn and loop checks have been
ccmpleted.
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14.2-145 Amendment 12
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- 1. By flow injection into a test line leading to the condensate storage tank (CST), and
- 2. By flov injection directly into the reactor vessel.
Tne earlier set of CST injection tests consict et man.ual and au:omatic mode starts at 200 psig and near rated reactor pressure conditions. The pump discharge pressure during these tests is throttled to be 100 psi above the reaccor pressure to simulate the largest expected pipe)ipe pressure drop. This CST testing is d "* t den nstrate general system operability and for 15Had7i making controlier adjustments.
Reactor vessil injection tests follow to complete the controller adjustments and to demonstrate automatic starting from a cold standby condition. " Cold" is defined as a mininum 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without any kind of HFCI operation. Data will be taken to determine the HPCI high steam flow isolation trip setpoint while injecting at rated flov to the reactor vessel. Depressing the manual initiation puanbutton is defined as automatic
(; starting or autonatic initiation of the HPCI system.
After all final controller and system adjustments have been determined, a defined set of demonstration tests must be performed. Tvu consecutive reactor vessel injections starting from cold conditions in the automatic mode r.uct natistactorily be perfcrmed to demonstrate systen reliability. Following these tests, a set of CST injections are done to provide a benchmark for comparison with ftture s arveillance tests.
After the auto start portion of certain of the above
_ tests is completed, and while the system is still operating, small st ep dicturbances in speed and flow command are input (in man.lal and automatic modes respectively) in ordar to demonstrate satisfactory stability. This is to be done at both low (above minimum turbine speed) and near rated flow initial conditions to span the HPCI operating range.
A continuous running test is to be scheduled at a convenient time during the startup test program. This demonstration of extended operation should be for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or until steady turbine and pump conditions are reached or until limits on piant operation are
( encountered.
14.2-167 Amendment 14
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above the reactor pressure to simulate the largest expected pipeline pressure drop. This CST testing is h3TEDI done to demonstrate general system operability and for making) controller adjustments.
Reactor vessel injection tests follow to complete the controller adjustments and to demonstrate automatic starting from a cold standby condition. " Cold" is defined as a minimum 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without any kind of RCIC operation. Data will be taken to determine the RCIC high steam flow isolation trip setpoint while injecting at rated flow to the reactor vessel.
After all final controller and system adjustments have been determined, a defined set of demonstration tests must be performed. Two consecutive reactor vessel injections starting from cold conditions in the automatic mode must satisfactorily be performed to demonstrate system reliability. Following these tests, a set of CST injections are done to provide a benchmark for comparison with future surveillance tests.
After the auto start portion of certain of the above tests is completed, and while the system is still
' operating, small step disturbances in speed and flow command are input (in manual and automatic mode respectively) in order to demonstrate satisfactory stability. This is to be done at both low (above minimum turbine speed) and near rated flow initial conditions to span the RCIC operating range.
A demonstration of extended operation of up to two hours (or until pump and turbine oil temperature is stabilized) of continuous running at rated flow conditions is to be scheduled at a convenient time during the startup test program.
Depressing the manual initiation pushbutton is definr3 as automatic starting or automatic initiation of the RCIC system.
- d. Acceptance Criteria Level 1:
- 1. Following automatic initiation, the pump discharge
, flow must be equal to or greater than rated flow as specified in Section 5.4.6 within the time specified by the GE startup test specification.
14.2-165 Amendment 14
HCGS VSAR 01/86 ,
s 1
_e ,
d.
Acceptance Criteria Level 1:
- 1. Following automatic initiation, the pump discharge flow must be equal to or greater than the rated flow, and within the time specified in :
Table 3.3.3-3 of the Technical Specifications.
- 2. The HPCI turbine shall not isolate or trip during automatic or manual start tests.
Level 2:
- 1. The speed and flow control loops are adjusted to meet the decay ratio specified in the GE startup test specification.
- 2. The turbine gland seal system is capable of preventing steam leakage to the atmosphere.
- 3. The delta-pressure setpoints for HPCI steam supply line high flow shall be calibrated to technical specification requirements using actual flow , - -
conditions.
- 4. In order to provide overspeed and isolation trip avoidance margin, the transient start speed peaks must not exceed the requirements of the GE startup test specification.
14.2.12.3.14 Selected Process and Water Level Reference Leg Temperatures
- a. Objectives i
- 1. Te establish Icw ;p :d limit; for the i raciscelation pu;p; to Ovcid ;;;1:nt t;;,;rature ,f
- i
- tratification in th
- ::::ter pr;;;;re v;;;;l -
I To ensure that the measured bottom head drain 1/. temperature corresponds to bottom head coolant l
i temperature during normal operation.
l 14.2-168 Amendment 14
t .-
. . ) '
AJ. To measure the reactor water, level instrument -
7 reference leg temperature and recalibrate the affected indicators if the measured temperature is different than expected.
- b. Prerequisites --
System and test instrumentation have been installed. l
- c. Test Method During initial heatup at 50t standby conditions, t h e- g better drai.= line temperature and applicable reacter- ,
/
parereterc are monitored 20 the recircul: tion pu=p speed is Slewly levered te determ!"e the preper retti,"g_
I2UdM IC4NI of the Ic" speed limiter.l Thepparameters'abweE!Are UMF 194- also monitorea curing plannea recirculation pumpTtrips fG**REF to determine if temperature stratification occurs in "37 "R4J' N N, the idle loop (s) and to assure that idle loop-to-bulk coolant temperature differentials are within Technical Specification limits prior to restarting the pump (s).
The bottom drain line temperature and applicable parameters are monitored when core flow is 100% of
, rated flow.
i .
A test is also performed at rated temperature and pressure under steady state conditions to verify that .
the reference leg temperature of the.~ level ,
instrumentation is the value assumed during initial calibration. Recalibration will L'ofperformed if necessary. ,
- d. Acceptance Criteria Level 1: '
- 1. The reactor recirculation pumps shall not be -
started unless the' loop to loop delta-temperatures and steam dome to bottom drain delta-temperatures are within the technical specification limits.
Level 2:
- 1. During two pump operation at 100% core flow, the difference between the bottom drain line thermocouple and recirculation loop thermocouple is within the delta-temperature required in the GE l
-(% startup test specification.
1 1
1 14.2-169 Amendment 14 ;
l I
n e
- 2. The difference between actual reference leg temperature and the value used for calibration is less than the amount specified in the GE startup test specification.
14.2.12.3.15 System Expansion -- NSSS
- a. Objective INSSSI The test objective is to demonstrate that maior/ + .
components and piping systems ;;rsustest th; elen0 are free and unrestrained with regard to thermal expansion.
- b. Prerequisites Fuel loading has been completed and cold plant data has i been. recorded (with the exception of those systems j testable during the Preoperational Phase).
- Instrumentation required has been installed and l calibrated. The system piping to be tested is i supported and restrained properly, i
- c. Test Method
(-
During heatup and cooldown, observations and recordings of the horizontal and vertical movements of major 9-equipment and piping in the NSSS an: ;; ; ili ; ry 07: : :: ::
are made in order to ensure that components are free to
! move as designed. Adjustments are made if necessary to l allow freedom of movement. Snubbers, whose testing requirements are governed by technical specifications, will be monitored for thermal movement. The systems to be monitored are listed in Section 3.9.2.
j i d. Acceptance Criteria 1 ,
i Level 1:
i
- 1. There shall be no evidence of blocking of the
- displacement of any system component caused by t thermal expansion of the system.
1 2. The piping displacements at the established
- transducer locations shall not exceed the '^
allowable values specified by the piping designer, k.
j 14.2-170 Amendment 14 l
{ .a . . - -
' ,\
[
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d.- Acceptance Criteria Level 2:
During a simulated main control room evacuation, the ability to bring the reactor to hot standby and subsequently cool down the plantiand control vessel pressure and water level shall be demonstrated using equipment and controls located outside the main control room.
14.2.12,3.27 Recirculation Flow Control a.
Objectives
,1. To determine plant response to changes in the recirculation flow
- 2. To optimize the setting of the master flow controller I
/
- b. Prerequisites The. reactor is operating at steady-state conditions at the required power level.
- c. Test Method With the mid-power reactor plant at the mid-power load lihe, the recirculation speed loops are tested using large plus and minus step changes and the speed controller gains are optimized. lAf ter the speed 100pc- p /
nafe teen Optimized, the syster may be evitched to the,/
macter manual mede :nd the master centroller Optimi=edi When the plant is tested along the 100% load line, the recirculation system shall be tested by inserting small plus and minus step changes in the local manual and j master manual modes. ,
i i
.-- l l 9
's t . 1 14.2-1S7 Amendment 14 l
{
s
- c. Test Method.
During the performance of the RHR shutdown cooling mode test, the SACS will also be evaluated to determine the heat removal capacity of the system and demonstrate the capability of achieving cold shutdown within the time specified in the design specificiation.
During normal operation, the SACS will be tested at various power levels to evaluate heat exchanger performance.
- d. Acceptance Criteria Level 1: l The SACS heat exchangers shall have sufficient heat removal capacity to meet the cooldown requirements specified in Section 9.2.2.1.1.a and 5.4.7.1.1.1.
Level 2:
The SACS heat exchangers shall meet or exceed the design heat removal capacity listed in Table 9.2-4. l 14.2.12.3.39 BOP Piping Vibration and Expansion
'INSBLT ~-
- A 7'
'TP.i; test a;; inc!;d:d in Occti;n; 14.2.12.3.15 ;nd 14.2.12.3.310 14.2.12.3.40 Confirmatory Inplant Test of Safety-Relief Valve Discharge
- a. Objective The objective of this test is to confirm assumptions and methodologies used in the plant unique analysis (PUA) (see a summary report in Appendix 3B) and show that the loads and structural responses documented in the PUAR for SRV discharge related loads are 14.2-198a Amendment 10 i , _
r-
. INSERT A FOR PAGE 14.2-198a 14.2.12.3.39 BOP Piping Vibration and Expansion BOP piping vibration testing is included in Section 14.2.12.3.31.
BOP Piping System Expansion
- a. Objective The test objective is to demonstrate that major components and piping systems throughout the plant are free and unrestrained with regard to thermal expansion.
- b. Prerequisites Fuel loading has been completed and cold plant data has been recorded. Instrumentation required has been installed and calibrated. The system piping to be-testing is supported and restrained properly.
- c. Test Method During heatup, observations and recordings of the horizontal and vertical movements of BOP piping systems are made in order to ensure that components are free to move as designed. Adjustments are made if necessary to allow freedom of movement. Snubbers, whose testing requirements are governed by technical specifications, will be monitored for thermal movement. The systems to be monitored are listed in Section 3.9.2.
- d. Acceptance Criteria Level 2
- 1. There shall be no evidence of blocking of the displacement of any system component caused by thermal expansion of the system.
- 2. Inspected hangers shall not be bottomed out or have the spring fully stretched.
- 3. The position of the shock suppressors shall be such as to allow adequate movement at operating temperature.
- 4. The piping displacements at the established transducer locations shall not exceed the limits specified by the piping designer, which are based on not exceeding ASME Section III Code stress values.
These specified displacements will be used as acceptance criteria in the appropriate startup test procedures.
. _ m _ _ _ . . _ _ _ . - . . _
flfD2g (L),Q-['f(cGyyp,3Qg;p 4
TEST OPEN HEAT VESSEL UP 1 2 3 4 5 4 NO. TEST NAME
-( 22)
X X X X X X 1 Chanical and Radiochemical X 2 Radiation Measurenent X X 3 Ebel Ioading X f 4 Eull (bre Shutdown Margin X X X( 2) X( 2) X( 2) XC I 5 Cbntrol Icd Drive X
, 6 SRM Perfonnance X 8 IBM Perfonnance X X X X X X 9 LPRM Calibration X X X X X X
' 10 APRM Calibration X 11 Process Computer X X X(3) X 12 RCIC X X HPCI X 13 14 Selected Process Tenp X X(4) hX X
l 14 15 Hater level Ref Iag Tenp Systen Expansion X
/ X X X
X X TIP t.hoertainty- X X 16 X X X X X X 17 Core 'Perfonnance X
- 3B - Stean Production Core Pwr-Void Mode Response X X 19 l
Pressure Regulator X X X X X X 2 2)
Feed Sys-Setpaint Changes X X X X X X X 21 Red Sys-Ioss EW Heating X(
l 21 XI, 21 Medwater Pirnp Trip Max EW Runout Capability X(
21 22 'Iurbine Valve Surveillance X(8) X(
23 MS1V Functione.1 Test X XI11) X(12) X(13)
X I 23 MSIV Ebil Isolation X(
24 Relief Valves X X( 20) X( 20)
X(15) 25 'lurbine Trip & Ioad X X(16) X(
Rejection 26 Shutdown Outside CRC X 27 Recirculation Flow (bntrol X(14) X(18)
X X~
28 Recirc-<he Pump Trip 2 RPT Trip-@o Ptznps X(19)
Decirc Systen 1%rformance X X X X
! 2 2 Recirc Planp Runback X 2 Recire Sys Cavitation X 30 Ioss of Offsite Pwr X X
31 Pipe Vibration X- X X X X X 2 Decire Flow Calibration 32 IWCU X( 23) 33 RHR X( 23) f Drywell & Stean 'Iunnel X X X X 34 Gooling X X X
! 35 Gaseous Radweste X X 38 SACS Perfonnance 40 Confirmatory In-Plant Test X FSAR 3/7 I
i
- - - - - - .- ~ _ _ _ _ _ _ _ _ _ , _ _ _ _
y (1) wst conditions refer to plant con:11tions on Figure 14.2-4 (2) Perform 'Ibst 5, timing of 4 selected control rods, in conjunction with expected scrams (3) Dynamic System 'Ibst Case to be conpleted between test conditions 1 and 3 (4) After recirculation pump trips (natural circulation)
(5) Between 80 and 90 percent thermal power, arri near 100 percent core flow (6) Max EW Runout Capability & Recirc Pimp Runback must have already been empleted (7) leactor power between 80 and 90 percent (8) leactor power between 45 and 65 percent and 75 and 90 percent (9) Deleted (10) At maximin power that will not cause scran (11) Perform between test conditions 1 and 3 9
D (12) Beactor power between 40 and 55 percent (13) Icactor power between 60 and 85 percent
)
) (14) Between test conditions 2 and 3 (15) Generator load rejection, within bypass valve capacity (16) Beactor power between 60 and 80 percent at core flow > 95 percent - turbine trip (17) Ioad rejection (18) Between test conditions 5 and 6 (19) >50% power and >95 core flow, and perfonn .
.) before 'Iurbine Trip & Ioa:1 Bejection
(:D) Check SRV operability durirg major scran tests (21) Ierformed during cooldown frm test condition 6 HOPE CREEK
~
GENERATING STATION FINAtSAFr.TY ANALYSIS REPORT-(22) 'Ihe test number correlates to FSAR Section 14.2.12.3 x where x is the indicated test ntnber.
TEST SCHEDULE AND CONDITIONS (23) May be performed any time test conditions permit.
FIGURE 14.2-5 Amendment 14,01/86
OUESTION 210.2 (SECTION 3.9)
Provide the data that the information identified as "later" in Tables 3.9-5d, 3.9-5q and 3.9-5s will be submitted.
RESPONSE
__The allowable forces and moments on the equipment nozzle connection will be met.\ IThe actu:1 v lucc will bc available in Jeuwery 1900 after the piping : built On:1ysic/ reconciliation effort is cemoleted.
. - Tw= CA%D VAWES CF WeCBS Anb MC016DD5 kAV6 OEL:;Q PRDVtb6b iki TF6 ffA/E HEN _ T41%65 i
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210.2-1 Amendment 14 l
- 4 HCGS FSAR 10/84 PSE&G plans to conduct that at-power surveillance testing prescribed by the BWR 4 version of the NRC's Standard Technical Specifications.
\s As surveillance procedures have become available and implemented, subsequent reviews have identified the need to utilize temporary alterations required for the proper performance of certain at power surveillance tests. When teraporary alterations are utilized, they are strictly controlled by an administrative program which has been designed to implement the app'licable recommendations of IE Information Notice 84-37.
<~
421.22-4 Amendment 8
- . - - . _ . ~ . .
HCGS FSAR 10/84 l OUESTION 430.125 (SECTION 9.5.7)
For the diesel engine lubrication system in Section 9.5.7 provide the following information: 1) define the temperature differentials, flow rate, and heat removal rate of the interface cooling system external to the engine and verify that these are in accordance with recommendations of the engine manufacturer;
- 2) discuss the measures that will be taken to maintain the required quality of the oil, including the inspection, frequency of inspection, and replacement when oil quality is degraded;
- 3) describe the protective features (such as blowout panels) provided to prevent unacceptable crankcase explosion and to mitigate the consequences of such an event; and 4) describe the ,
capability for detection and control of system leakage and the frequency it will be checked. (SRP 9.5.7, Parts II & III)
RESPONSE
- 1) Flow rate and heat removal rate of the safety auxiliaries cooling system (SACS) is provided in Table 9.2-4. The maximum cooling water inlet temperature to the diesel generator skid is 950F as given in Table 9.2-3. The outlet temperature will vary with the actual heat load and actual inlet temperature of the cooling water. It has been
( verified that these parameters are in accordance with the recommendations of the diesel generator manufacturer.
- 2) Procurement specifications for diesel engine lubricating oil and governor oil will incorporate the engine manufacturer's recommendations for quality, purity and lubrication properties. Sampling will be performed every 18 months or after 750 hours0.00868 days <br />0.208 hours <br />0.00124 weeks <br />2.85375e-4 months <br /> of engine operation. Oil samples will be analyzed to assure that:
- 1. Oil degradation has not occurred l
- 2. The oil continues to meet the specifications of HIL-L-W Dj 2 : 0=.
'S The analysis report will determine the need for replacement of the lubricating oil.
In addition, surveillance testing demonstrates diesel engine operability and will include performance monitoring of the diesel engine lubricating oil system. The installed strainer and filter will remove sediment or other deleterious material. Scrainer or filter cleaning will be performed at the onset of increased differential pressure across the strainer or filter. Residue will be analyzed to determine 430.125-1 Amendment 8 l
-e
RESPONSE
C
- a. The lube oil consumption rate for the standby diesel U49 generator at the rated 4430 KW BHP) is 1.12 to 1.55 gallons per hour. The engine manufacturer, Colt Industries, indicates that the lube oil consumption rate does not vary appreciably with the engine load level.
The engine manufacturer indicates that a lube oil consumption rate of 3 gallons per hour would be considered excessive and should be investigated and remedied.
- b. The diesel engine manufacturer recommends that the diesel engine sump be kept " topped off" in the standby-condition and not allowed to be at the " minimum level" condition so that it is always ready.to operate for the maximum duration required.
To raise the lube oil level in the diesel engine sump from the minimum level to the full running depth, approximatly 220 gallons of lube oil is required, which is the capacity of'four 55 gallon storage drums of oil.
At a consumption rate of 1.55 gallons per hour the engine can operate for 142 hours0.00164 days <br />0.0394 hours <br />2.347884e-4 weeks <br />5.4031e-5 months <br />. To operate for 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br />, an average consumption rate of 1.31 gallons per hour should not be exceeded, which is in the expected consumption range. The lube oil make up tank contains 250 gallons of oil, therefore, the make up tank can raise the sump level from minimum level to full with an additional 30 gallon in reserve. The lube oil make up tank can therefore maintain the diesel engine in the-operating lube oil range for 161 hours0.00186 days <br />0.0447 hours <br />2.662037e-4 weeks <br />6.12605e-5 months <br /> at a' consumption rate of 1.55 gallons per hour.
A minimum of 550 gallons of lube oil per diesel generator (forty 55 gallon drums, total) will be stored on site for emergency makeup. The 550 gallon storage of lube oil exceeds the required lube oil makeup for a 14-day supply at a maximum, worst case, consumption rate of 1.55 gallons per hour.
Apgegygggnwr Therefore, with the additional onsite storage of forty
&#fr9M '
55 callon drums of lube oil, as required b h -
1 J'Jechr.ical Opecific; oil to operate tier 4, engines the diesel there willforbe14sufficient days fromlube the l low level sump indication.
- c. Operator action on failure of the solenoid valve to provide adequate engine lube oil sump makeup capability
(
430.131-2 Amendment 10 l l
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HCGS FSAR 10/84 I' makeup' tank in the unfilled areas is prevented by lube oil vapor coating, normally found on unflooded sections of lube oil tanks.
Prevention of corrosion of the lower head of the SDG lube oil makeup tank due to moisture accumulation is addressed in the second paragraph to part d of this response,
- c. The vent and emergency pressure relief vent are terminated indoors, directly above the tank. The fill line is routed to the outside (west) of the auxiliary building at elevation 105 feet 0 inches, 3 feet above grade. The line is capped and has a normally closed isolation valve located.in the building to prevent water from entering the line. It is not protected from missiles and tornadoes because it is not safety-
$ranca krumST&mVEN@cEtuRGSl y
- d. In accordance withf%:chnic 1 pecific ti n;, twenty 55-gallon drums of diesel engine lubricating oil are stored and available for use if diesel operation is required for a prolonged period. Additional information on lube oil make up requirements is provided in the response to Question 430.131. The lube oil make-up tank bottom is hemispherical. The line to f
the diesel generator sump is approximately 1.75 inches above the bottom of the dish and is located ten inches off the centerline of the tank, reference Figure 430.135-1. Should there be any carry over into '
the transfer line, it would be trapped in the strainer and/or filter after entering the engine sump.
A normally closed drain valve is provided at the low point of the tank, reference Figure 9.5-27 and 430.135-1.
The drain valve will be opened in accordance with plant operating procedures to remove any deleterious sediment, water or other material that may accumulate in the bottom of the tank.
6
(
430.135-3 Amendment 8
,= - -. .- - . - - . . - .- -
< simulation.
acceptable.
The test results were found to be (
l 4.0 QUALITY ASSURANCE i The safety-relief valves were all individually manufactured
- and tested according to the General Electric (GE) quality i assurance program accepted by the NRC (Reference 7.1). The j program was developed to assure that each valve met the requirements of the purchase specification. Quality
- assurance records documenting compliance with the purchase
! specification are on file at GE.
Quality assurance review of certification and/or witnessing
- of inspection of paits and tests performed by the ,
i manufacturer assured compliance to the specification I requirements. In addition, ASME-certified Boiler Inspectors 1 performed independent inspections and reviews for manufacturer's compliance to American Society of Mechanical Engineers (ASME) requirements. Customer reviews and >
- inspections of the manufacturer further assured achievement j of the compliance needed.
The manufacturer has performed ASME-required tests and
! obtained ASME certification of the prototype valve design j for flow capacity, set pressure, and blowdown. Prior to (
. delivery to the HCGS, all production valves were tested and (
l met the GE design specification for the power and safety :
actuation mode, for set pressure, for blowdown capacity, and for seat leakage.
i Note: The blowdown capacity is a function of the valve's i
main disc seat diameter. Capacity is controlled by controlling this dimension within appropriate tolerances.
i 5.0 VALVE OPERABILITY I
5.1 SRV Performance Monitorina l a. Thermocouples are installed in the discharge line of each SRV. A temperature increase in the discharge piping indicates leakage through the i
pilot disc. Valves leaking detectably are j replaced at the next opportunity.
5 l
- b. The SRVs are fully tested during startup of the
! reactor prior to commercial operation. Following ,
- refueling activities, valve operability is '
l verified by relief (manual) operation atoEEs4'* '
i !;r,eeerre '
l825's 25 PS8G\
440.7-6 Amendment 12 l 1
I -
4
[.
QUESTION 480.14 (SECTION 6.2.3)
Provide the following additional information related to potential bypass leakage paths given in Table 6.2-15.
- a. For each air or water seal demonstrate that a sufficient inventory of the fluid is available to maintain the seal 30 days following onset of a LOCA.
Note that the suppression pool cannot be considered a water seal. Lescribe the testing and proposed entries for the Technical Specifications that will verify the assumptions used in the analyses.
- b. For each path where water seals eliminate the potential j for bypass leakage, provide a sketch to show the location of the water seal' relative to the system isolation valves.
RESPONSE
HCGS does consider the suppression pool to be an effective water j seal. The suppression pool is a reliable source of water that
- can provide the required separation between the primary l( containment atmosphere and the environs. The suppression
- chamber's structural design is discussed in Section 3.8.2. Thus, we have considered it to be a water seal as indicated in l Section 6.2.3.
I j Delow is an item by item discussion of the ability of the air and water seal barriers identified in Table 6.2-15 to maintain l sufficient inventory for 30 days following a LOCA. For those
- valves maintaining a water seal, calculations have been done to
- _ verify that there is sufficient inventory for 30 days assuming l FD-Vol8 leakage' rates of ,10 ml/h per inch of nominal valve diameter, 4 AND unless.otherwise indicated below (Reference 1). Except for HPCI J6" l valveylTO V017
- nd TD-Y003, RCIC valvg(1TC-702; end TC-V0l", enc" ,
LR.".CS velve: ED-YOO3 :nd ED-?Oct,lall valves required to maintain ' AC- VD*l j
J' a water seal are 10 CFR 50 Appendix J, Type C tested. Those
- AwWrsmme valves that are not Type C tested will be-identified irh p
""G084" tect.nic:: :p :::::::::n as requiring periodic leakage testing in j J'o'rder to ensure the existence of the water seal.
Main Steam - A positive air seal is maintained through the j operation of the MSIV sealing system as discussed in Section,6.7.
1
- Feedwater Line - The feedwater line fill network is used to maintain a water seal in the feedwater-lines after a LOCA. The j _
operation of the network is discussed in Section 6.2.3.2.3.
f I5 <
a 480.14-1 Amendment 10 l
- T -Sa- - "C mmeh
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~ ~
pp g, , HPCI Turbine Steam Supply - There71s sufficient water inventory for a 30-day seal for valvderr Ve"?i Figure 480.14-2 is provided to show the location of the water seal relative to the system isolation valves.
Chilled Water from and to Drywell Coolers - There is sufficient water inventory for a 30-day seal for valves GB-V081, V082, V083, and V084. Figure 480.14-3 is provided to show the location of the water seals relative to the system isolation valves.
MD ggygg Instrument Gas Supply to\Drywell.- A positive air seal is pen maintained through the operation of the primary containment instrument gas system.
RWCU Supply - There is sufficient water inventory for a 30-day seal for valve BG-V001. Figure 480.14-4-is provided to show the ,
location of the water seal relative to the system isolation valve.
RCICTurbineSteamSupply-7Thereissufficientinventoryfora
[RPVOC' 30-day seal for valvecrc 'i;12 assuming a leakage rate of 5 ml/h per inch of nominal valve diameter. Figure 480.14-5 is provided to show the location of the water seal relative to the system isolation valve. .
Main Steam Line Drain'- There is sufficient inventory for a '. m.
30-day seal for valve AB-V039. Figure 480.14-6 is provided to show the location of the water seal relative to the system isolation valve. .
Recirculation Pump Seal Purge - There is sufficient inventory for a 30-day seal for valve BF-V098 and V099. Figure 480.14-7 is provided to show the location of the water seals relative to the system isolation valves. 4 asser ;
The containment purge lines \ connect to the FRVS system. Any f leakage will be collected and filtered by FRVS. !
Drywell Floor Drains and Equipment Sumps - The water barrier is j maintained by instrumentation-and controls that prevent the sumps f 1
esser - from being pumped dry. i Uf5, RACS Supply and eturnh is suf ficient Mwen44MM# or a valves ED-V003 and V004.
~
30-day sealt Figure 480.14-8 is ~
provided to show the location of the water seals relative to the :
system isolation valves.
asserl C \
E 480.14-2 Amendment 2 >
INSERT A FOR PAGE 480.14-2 (drywell inlet and outlet and torus inlet and outlet)
INSERT B FOR PAGE 480.14-2 The lines are seismically analyzed in the auxiliary building with a vertical leg approximately six feet long which INSERT C FOR PAGE 480.14-2 HPCI and RCIC Turbine Auxiliary Steam Supply, Service and Breathing Air to Drywell - These lines contain a temporary spool piece that is removed during normal operation and replace by a blind flange so that any leakage through the flange is into the reactor building enclosure.
Torus Water Cleanup Supply and Return - The suppression pool water forms an effective water seal for these lines.
Post Accident Sampling System (PASS) Supply and Return -
The liquid and gas sample lines to the isolation valves are Seismic Category I. The PASS sampling lines terminate in the PASS sample station. The PASS sample station location is described in Section 9.3.2.2.2.4. Any gaseous bypass leakage in the PASS sample station will be vented to the reactor building ventilation system / filtration, recirculation and ventilation system common return duct as described in Section 9.3.2.2.2.7. Any liquid bypass leakage in the PASS sample station will be collected in a sump located in the sample station which can be pressurized with the discharge being directed to the suppression pool.
?
i HCGS FSAR 10/83 QUESTION 480.34 (SECTION 6.2.6) d List the systems which penetrate the containment and are not vented and drained for the Type A containment leak rate test.
Those systems that are not vented and drained for the Type A test must meet ,the following requirements:
- 1) The system is protected against missiles and pipe whip;
- 2) The system is designated seismic Category I;
- 3) The system is classified Safety Class 2;
- 4) The system pressure is greater than the containment pressure at all times during the course of the accident;
- 5) The system will remain full of water for 30 days, and;
. 6) Both items 4 and 5 will be maintained when a single active failure is assumed in the system.
State whether or not these systems meet the above requirements.
L
RESPONSE
Those systems which penetrate the containment and are not vented and drained for the type A containment leak rate test are identified by note -
n-- --- '-ion Table 6.2-24, and in revised Section 6.2.3.2.3.
All systems noted above are: a) protected against missiles and pipe whip, b) designed to seismic Category I requirements, and c) classified as Quality Group B.
In addition, these systems will remain full of water for 30 days following an accidentm even after the assumption of a single active failure. Notef 9 ' 13 ; ron Table 6.2-24, and Section 2.3.2.3 discussf e m-o th '
aintenance of the water seal and pressure. We consider the water seal with a system pressure equal to the contaiment pressure sufficient to prevent bypass -
leakage of the containment atmosphere. Some system pressures, such as pump suction lines from the torus, could never be greater than the containment pressure.
480.34-1 Amendment 2 5 1