ML20074A139
| ML20074A139 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 05/10/1983 |
| From: | Bradley E PECO ENERGY CO., (FORMERLY PHILADELPHIA ELECTRIC |
| To: | Schwencer A Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8305120320 | |
| Download: ML20074A139 (138) | |
Text
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PHILADELPHIA ELECTRIC COMPANY 23O1 M ARKET STREET P.O BOX 8699 PHILADELPHI A. PA.19101
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t21st e41-4000 ANO SENSm AL CouMeak EUGENE J. BR ADLEY assoceA?a sansmas counsak DON ALD BLANKEN RUDOLPH A. CHILLEMI E. C. KI R K H A LL I
T. H. M AH ER CO RN ELL PAUL AUERBACH AsstsTaNT SENER AL CouNeak EDW ARD J. CULLEN. J R.
THOM AS H. MILLER. JR.
IRENE A. McKENN A assisTass? counsak bir. A. Schwencer, Chief Licensing Branch No. 2 Division of Licensing U.S. Nuclear Regulatory Commission Washington, DC 20555
SUBJECT:
Limerick Generating Station, Units 1 6 2
REFERENCE:
biceting between Containment Systems Branch (CSB)
Reviewer, b!r. F. Eltawila, and Philadelphia Electric Company on April 7, 1983
Dear bir. Schwencer:
The referenced meeting was held to discuss twenty issues of concern to the CSB.
As a result of the discussions, we will make changes to the FSAR, the Design Assessment Report and to the responses previously provided to Questions raised by the CSB. Attached are drafts of the changes prepared in response to issues 1, 3a, 3b, 4, 7, 8, 10, 11, 12, 13, 15, 16 and 18.
These draft changes will be formally incorporated into the FSAR revision scheduled for June 1983.
Also attached is a brief discussion of issue 17, indicating that a report on the functionality of the Limerick Purge G Vent Valves will be submitted to the NRC staff for review later in blay 1983.
8305120320 830510 g8 PDR ADOCK 05000352 A
Information responding to issues 5b, Sc, 5d and 5e will be pro-vided later in May 1983, as will information on issue 20.
Ver trul* yours, E.
. Br,dicy JTR/ cam c/1 Attachments Copy to: See attached service list
- cc: Judge Lawrence Brenner (w/o enclosure)
Judge Richard F. Cole (w/o enclosure)
Judge Peter A. b! orris (w/o enclosure)
Troy B. Conner, Jr., Esq.
(w/o enclosure)
Ann P. Ilodgdon (w/o enclosure) bir. Frank R. Romano (w/o enclosure) bir. Robert L. Anthony (w/o enclosure) bir, blarvin I. Lewis (w/o enclosure)
Judith A. Dorsey, Esq.
(w/o enclosure)
Charles N. Elliott, Esq.
(w/o enclosure) bir. Alan J. Nogee (w/o enclosure)
Thomas Y. Au, Esq.
(w/o enclosure) bir. Thomas Gerusky (w/o enclosure)
Director, Pennsylvania Emergency blanagement Agency (w/o enclosure) bir. Steven P. Ilershey (w/o enclosure)
James bl. Neill, Esq.
(w/o enclosure)
Donald S. Bronstein, Esq.
(w/o enclosure) b!r. Joseph II. White, III (w/o enclosure)
Walter W. Cohen, Esq.
(w/o enclosure)
Robert J. Sugarman, Esq.
(w/o enclosure)
Rodney D. Johnson (w/o enclosure)
Atomic Safety and Licensing Appeal Board (w/o enclosure)
Atomic Safety and Licensing Board Panel (w/o enclosure)
Docket and Service Section (w/o enclosure)
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__.!! The CSB review of the applicant's response to Question 480.7 has determined that l' the requirements of Appendix A to SRP Section 6.2.1.1.c concerning steam bypass l,, capability have been met wJth one exception. The exception is that the applicant must commit to the leakage test and surveillance requirernents sta:ed in Positions B.? and B.3 of Appendsx A to SRP Section 6.2.1.1.c includmg the specifsed
{li fregaencies. (Open item)
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flow rate of one spray system is 500 gpm.
With two spray systems in operation, the required efficiency would be halved.
The spray efficiency is typically on the order of 0.7 and, therefore, even with a single system is operation, the termination of the wetwell (and drywell) pressure increase is assured.
Required Efficiency of Spray Temperature 1 Wetwell Spray System 700F 0.22 l
900F 0.24 l
1200F 0.28 l
c.
The wetwell spray system is to be used to mitigate the consequences of suppression pool steam bypass high pressure.
Limerick is in compliance with the guidelines of SRP 3.2.2 and Regulatory Guide 1.26 because the safety-related design basis for the containment spray system is that it provide a means of pressure reduction, not heat removal.
Therefore seismic Category I/Ouality Group C standards are adequate for the wetwell spray headers.
The containment spray system is also designed to be operable following a loss of offsite power plus a single failure.
As discussed in Section 6.2.1.1.5.2, use of the containment sprays is only one option available to the operator to respond to high pressure resulting from steam bypass of the suppression pool.
The Quality Group designations for the containment spray system have not changed since the PSAR was submitted.
(
) Section 6.2.6.5.1 and Table 14.2-4 have been changed to provide the requested information.
e.
A visual inspection will be conducted prior to each integrated leak rate test to detect possible drywell-to-suppression bypass leakage paths.
A visual inspection of each primary containment vacuum relief valve assembly will be conducted during each refueling outage to verify that it is clear of foreign matter.
f.
The vacuum relief valve position indicator system has adequate sensitivity to detect a total valve opening, for all valves, that is less than the bypass capability for a small break.
Valve opening is detectable at a disk lift of 0.06 inches or greater above the valve 480.7-5 Rev. 14, 12/82
(
seat.
Even assuming that all the vacuum breakers are open by 0.06 inches, the corresponding leakage area, A//k, is well below 0.05 f tr.
Therefore, the valve leakage, which is based on the assumption that the valve opening is evenly divided among all the vacuum breakers, is well within the limits of acceptable bypass leakage.
Vacuumbreakerswillbetrea)_~'foroperabilityatan itSYe g.
interval specified by the technical specifications.74y Steve,lkce ferY v Yl be
<% ac&W su H Q Swg s%M T aed Sfutheitm (+.6.+. 2.4 ).
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Rev. 14, 12/82 480.7-6
'l leakage rate tested with that liquid.
The liquid leakage measured is neither converted to equivalent air leakage nor added to the Type B and C test totals.
Isolation valves tested with liquid are identified in Table 6.2-25.
The acceptance criteria for all penetrations and isolation valves subject to Type B and C tests are given in Chaper 16.
6.2.6.4 Schedulino and Reportino of Periodic Tests The periodic leakage rate test schedules for Types A, B and C tests are given in Chapter 16.
Type B and C tests can be conducted at any time during normal plant operations or during shutdown periods, so long as the time interval between tests for any individual Type B or C test does not exceed the maximum allowable interval specified in Chapter 16.
Each time a Type B or C test is completed, the overall total leakage rate for all required Type B and C tests is corrected for any differences noted.
Provisions for reporting test results are given in Chapter 16.
6.2.6.5 Special Testino Requirements 6.2.6.5.1 Drywell Steam Bypass Test
}
Following the drywell structural integrity test, described in i
Section 3.8.1.7, a preoperational drywell leakage rate test is i
performed at drywell design pressure.
Table 14.2-4 gives the test descriptions.
Preoperational and periodic drywell leakage rate tests at a reduced pressure, defined in Chapter 16, are performed following the preoperational end p;riedi: Type A test ask These drywel1 leakage rate tests verify, over
/ por:o 7
the design life of the plant, that no paths for gross leakage (49 ped @bc.#
from the drywell to the suppression chamber air space bypassing l
the pressure suppression feature exist.
The combination of the design pressure and reduced pressure leakage rate tests also verifies that the drywell performs adequately for the full range of postulated primary system break sizes.
The drywell leakage rate limits specified in Chapter 16 are based on a value of 10%
of the allowable bypass A//R for = mall breaks that are described.
in Section 6.2.1.1.5.4.
Drywell leakage rate tests are performed with the drywell isolated from the suppression chamber.
Valves and system lineups are the same as for the Type A test except any paths for equalizing d'rywell and suppression chamber pressure open during the Type A test are isolated.
The drywell atmosphere is allowed to stabilize for a period of one hour after attaining test pressure.
Leakage rate test calculations, using the pressure decay method, commence after the stabilization period.
6.2-83 Rev. 11, 10/82 4
-.- -,.,_. - ~.- - _ - --
O LGS FSAR The pressure decay method is based on drywell atmosphere pressure and temperature observations and the known drywell free air volume specified in Table 6.2-22.
Leakage rate is calculated from the pressure and temperature data, drywell free air volume, and elapsed time.
The periodic drywell leakage rate test pressures, test duration, and acceptance criteria are specified in Chapter 16.
Periodic drywell leakage rate tests are performed at the intervals dececlu rt specified in Chapter 16. Tks.sweei//uce 1mf w.'// he in wiYL owr. 3% dan] 7Feln%I e
6.2.7 POST-ACCIDENT SYSTEM ISOLATION Spe#;egt;W (4.C.2.l.O Following an accident in which significant fuel damage is postulated to occur, a number of plant systems whose piping penetrates the primary containment may contain highly radioactive fluids.
Adequate system isolation features exist to ensure that the integrity of these systems will be maintained.
6.2.7.1 System Isolation Provisions The boundaries of potentially contaminated systems are adequately isolated by one of the following:
a)
Two normally closed manual valves b)
One normally closed manual valve (low pressure piping) c)
One or two normally closed manual valves and a cap d)
One safety relief valve or one rupture disc e)
Two check valves f)
One remotely actuate'd valve and one check valve g)
Two remotely actuated valves In cases where's remotely actuated valve is required to change-position to provide system isolation, the valve receives an auto isolation signal.
In some cases a system isolation valve does not receive a direct isolation signal but is interlocked to close when a containment isolation valve or other valve opens to permit fluid flow from the containment.
I Table 6.2-26 lists remotely-actuated system isolation valves, their normal and required accident positions and their actuation
)
Containment isolation valves that also provide post-signals.
accident system isolation are not included in this table but are listed in Table 6.2-17.
Rev. 15, 12/82 6.2-84
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-b Th_e. applicant has ret adequately demonstrated why inadvertent actuation of both __ -
l drywell spray trains sWuId n6i be considered in the esaliHUoE~of the~drisell_ floor
- reverse pressure design basis and the drywell external prersure design basis. Also l the drywell floor reverse pressure desigrr basis must be stated because the FSAR and Design Assessment Report (DAR) give conflicting values. (Open item) i 74 A-
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, LGS FSAR OUESTION 480.4 (Section 6.2.1.1)
Provide a detailed description of the administrative procedures that will preclude the actuation of both drywell spray networks whenever the suppression pool temperature is below 1050F (see FSAR Section 6.2.1.1.4).
RESPONSE
Operation of the drywell sprays at Limerick will be governed by appropriate emergency procedures, which will be written and revised to implement the BWR Owners Group Emergency Guidelines.
There will be no other procedural requirements or administrative directives that will cause drywell sprays to be used.
At present, the emergency procedures will be written to Revision 2 of the Owners Group Emergency Guidelines, which is currently under review by the Commission.
Specifically, the following steps in the guidelines direct use of the drywell sprays: PC/P-3, PC/P-6, SP/L-3.3 and SP/L-3.4.
At each of these steps, the operators will be directed first to determine if the present combination of suppression chamber temperature and drywell pressure fall.below the drywell spray initiation pressure limit.
If the combination of parameters is below the limit, the operator is directed to initiate drywell spray with a slow rate not to exceed the maximum drywell spray flow rate limit.
Both of these limits will be calculated in accordance with Appendix C to the Owners Group Emergency Guidelines.
The specific details of the calculations are given in Appendix C, Section 8.0 for the drywell spray initiation pressure limit and Section 9.0 for the maximum drywell spray flow rate limit.
These limits prevent the generation of drywell negative pressures relative to secondary containments and suppression pools that could be damaging to the containment vessel.
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LGS DAR 1
4 TABLE 1.3-2 (continued)
(Page 3 of 10) l Criteria LGS Load _or,Ebengmepon N_RC Acc,egtance Criteria Source Posataon i
j
- b. Large Nono - Plant unique load NUREG-0487 Not Applicable structures where applicable.
No large structures
- c. Grating P drag vs. grating area NUREG-0487 Acceptable correlation and pool velocity vs. elevation.
I Pool velocity from the l
PSAM.
P drag multi-4 plied by dynamic load iactor.
1
- 4. Wetwell Air Compression kAdQ(pr{g g
- a. Wall Loads Direct application of NUREG-0487 Acceptable the PSAM calculated (O 4 Ps tp (M-4 p3 pressure due to wetwell compression.
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- b. Diaphragm 5.5 paid for diaphraqr, NUREG-0808 Acceptable.
Upward Ioads loadings only.
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- 5. Asymmetric IDCA Use 20 percent of max-NUREG-0487 Acceptable
'D E516M AP0p_- A Psto Pool imum bubble pressure Supplement 1 statically applied to 1/2 of the submerged boundary.
C. Steam Condensation and Chuqqing Loads
- 1. Downcoenaac Lateral Loads
- a. Single-Vent Dynamic load to end of NUREG-0808 Acceptable Ioads (24 in.)
vent.
Half sine wave with a duration of 3 to 6 as and corresponding maximum amplitudes of 65 to 10 Klbf.
- b. Multiple-Vent Prescribed variation of NUREG-0808 Acceptable Loads (24 an.)
load per vent vs. nuinber of vents.
Determined from single vent dyna-mic load specification Rev. 2, 03/83
LGS DAR TABLE 1.4-1 (Page 1 of 3)
C,0NTAINMENT DESIGN PARAMETERS Suppression Drywell Chamber DRYWELL AND SUPPRESSION CHAMBER Internal design pressure, psig 55 55 External to internal design 5
5 differential pressure, psid Drywell deck design -differential 30 lLT) pressure, psid vowsWMD vpW Asp Design temperature, OF 340 220 Drywell net free volume 248,950 including downcomers, ft8 Suppression chamber free volume, ft*
i L'ow level 161,350 High level 149,425 Suppression pool water volume, ft3 Low level 115,903 High level 127,756 Suppression pool net surface area, 4974 outside pedestal, ft:
Supression pool depth, ft Low level 22' Normal level 23' High level 24'-3" VENT SYSTEM Number of downcomers 87 i
Nominal downcomer diameter, ft 2
Total vent area, ft2 256.5
}
Section 1.8 provides references to Regulatory Guides discussed in the FSAR.
Regulatory Guides specific to this section are discussed in this section.
3.8.3.3 Loads and Loadino Combinations Tables 3.8-2 and 3.8-5 through 3.8-8 list the loading combinations used for the design and analysis of the containment internal structures.
The internal structures are also analyzed for hydrodynamic loads resulting from main steam relief valve discharge and LOCA phenomena.
For a definition of loads and loading combinations (including hydrodynamic loads), see Refs 3.8-1 and 3.8-2.
3.8.3.3.1 Diaphragm Slab and Reactor Pedestal Table 3.8-2 lists the loading combinations used for the design of the diaphragm slab and reactor pedestal.
Descriptions of the loads are as follows:
a.
Dead Load, Live Load, and Seismic Loads For a description of dead load, live load, and seismic loads, see Section 3.8.1.3.
b.
Desion Basis Accident Pressure Load The diaphragm slab and the reactor pedestal are designed for the follcwing pressures:
1.
Maximam pressure: 55 psig in the drywell and the suppressicn chamber Pcv]N vVA@
2.
Maximum differential pressure: 30 psigA(55 psig in the drywell and 25 psig in the suppression chambar).
cPC P5iS kp % 7(.35 Y M % % &Tf M d GMW M J M 3.p t c.
Therma 1 Loads g g n;gK_ g ]
)
The temperatures above and below the diaphragm slab for the operating and the postulated design accident conditions are shown in Table 3.8-3.
The portions of the reactor pedestal above and below the diaphragm slab are designed for the drywell and suppression chamber maximum temperatures listed in Table 3.8-3.
Thermal effects anticipated at the time of the structural acceptance test are insignificant, since the difference in temperatures inside and outside the containment during the test is small.
3.8-30
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pool.
As the vapor formed in the drywell is condensed in the suppression pool, the temperature of the suppression pool water peaks and the suppression chamber pressure stabilizes.
The drywell pressure stabilizes at a slightly higher pressure, the difference being equal to the downcomer submergence.
During the RPV depressurization phase, most of the noncondensable gases initially in the drywell are forced into the suppression chamber.
However, following depressurization the noncondensables redistribute between the drywell and suppression chamber via the vacuum relief valve system.
This redistribution takes place as steam in the drywell is condensed by the relatively cool ECCS water which is beginning to cascade from the break causing the drywell pressure to decrease.
~
Two cases leading to potentially rapid drywell depressurization were considered for wetwell-to-drywell vacuum breaker sizing:
The inadvertent actuation of one drywell spray train a.
(10,000 gpm B 900F, assumed) b.
Maximum ECCS spillage (7750 lbm/sec B 1400F exit temperature, assumed) during the depressurization phase of the large recirculation outlet line break LOCA g
[
Each case was considered to determine the number of vacuum breaker valve assemblies required to ensure that the maximum differential pressure across the diaphragm slab in the upward direction does not exceed allowables.
For the analyses, a conservatively low 3 psid across the diaphragm slab was used, well below the present design allowable of JC psids CPW Ap.p.
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In the analyses done for both cases, a. and b.,
it was conservatively assumed that all noncondensables have been removed to the wetwell vapor region prior to drywell depressurization.
I In addition to this, for the Case a. accident a 100% spray efficiency, together with a drywell temperature of 2730F, combine with the assumptions regarding spray rate and inlet temperature noted above, to render this analysis conservative.
This results in a net drywell energy removal rate of approximately 321,000 Btu /sec.
The analysis for Case b. assumes a drywell saturation temperature of 2620F, an ECCS drop fall height of 42 feet, an average drop diameter of 1 inch (for calculating condensation heat transfer to the falling ECCS spillage), and an average heat transfer coefficient of 2300 Btu /hr-ft2-oF (for calculating heat transfer from the drywell vapor region to the pool of ECCS spillage collected on the drywell floor).
These considerations, combined with the assumptions regarding noncondensables and ECCS spillage rate and temperature, yield a net drywell energy removal rate of approximately 318,000 Btu /sec for an ECCS spillage spray N.
/
effectiveness of 34S..
6.2-9
I LGS FSAR TABLE 6.2-1 (Page 1 of 2)
CONTAINMENT DESIGN PARAMETERS SUPPRESSION DRYWELL CHAMBER DRYWELL AND SUPPRESSION CHAMBER Internal design pressure, psig 55 55
~~ ~ ~ ~ ~ External' to internal design ~ ~ - ~
' ~ ~ ~ ~
~~~
~~~
~~~ ~
~~
5 5
differential pressure, psid Drywell deck design differ'ential--._ -_- 3 0 _ __ _ - _ _ -- #D pressure, psid Dew m ee uewman Design temperature, OF 340 220 Drywell net free volume, ft3 248,950(2)
Design leak rate, % by weight / day 0.5 0.5 Maximum allowable leak rate, 0.5 0.5
% by weight / day Suppression chamber free volume, ft3 Low level 161,350 High level 149,425 Suppression pool water volume, ft3 Low level 115,903(2)
High level 127,756(2)
Suppression pool surface area, ft2 4974(a) l (outside pedestal)
Suppression pool depth, ft Low level 22' High level 24' 3"
,s' VENT SYSTEM i
Number of downcomers 87 Rev. 19, 04/83
_ =
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SUMMARY
OF SHORT-TERM CONTAINMENT RESPONSES TO RECIRCULATION LINE AND MAIN STEAM LINE BREAKS MAIN RECIRCULATION STEAM LINE LINE BREAK BREAK Peak drywell pressure, psig 44.02 36.20 M hl*&M)
Peak drywell deck differential pressure, psid b
25.995 19.5
?-
Time of peak pressures, see 13.66 20.12 Peak drywell temperature, OF 290.9 330 Peak suppression chamber pressure, 30.57 30.55 psi 9 Time of peak suppression chamber 34.75 50
(,
pressure, see Peak suppression pool temperature 135.7 136 during blowdown, OF Calculated drywell pressure margin, %
20 34 Calculated suppression chamber 44 44 pressure margin, %
Calculated deck differential 13 35 pressure margin, %
Energy released to containment 262.23 l
at time of peak pressure, 108 Btu Energy absorbed by passive heat 0
0 i
sinks at time of peak pressure, 10* Btu
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l and temperature transient resulting from postulated steam bypass of the suppression pool fo!!owing a LOCA necenary to estab!!sh the environme'ntal qualification conditions for the suppression chamber. (open Item) j I
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LGS FSAR CHAPTER 3' DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT AND SYSTEMS TABLES (Cont'd)
Table No.
Title 3.11-1 Pressure, Temperature, and Relative Humidity Environ-mental Conditions in which NSSS Components have been Designed to Operate 3.11-2 Accident Environment (Primary Containment) Maximum Environment Envelopes for which NSSS Components have been Designed to Operate in and/or Remain in a Safe Condition 3.11-3 Accident Environment (Reactor Enclosure) Maximum Environment Envelopes for which NSSS Components have been Designed to Operate and/or Remain in a Safe Condition 3.11-4 Radiation Environmental Conditions for which NSSS Components have been Designed to Operate In and/or.
Remain in a Safe Condition 3.11-5 Calculated Normal and Maximum Plant Environmental Conditions 3.ll-Sa Calculated Primary Containment Dose Rates 3.11-5b Calculated SGTS Carbon Filter Dose Rates 3.11-Sc Calculated Secondary Containment Dose Rates 3.11-5d Calculated 24 Inch Recombiner Piping Dose Rates 3.11-Se Calculated 6 Inch ECCS Piping Dose Rates 3.ll-5f Calculated 14 Inch ECCS Piping Dose Rates 3.11-5g Calculated 16 Inch ECCS Piping Dose, Rates 3.11-Sh Calculated 18 Inch Shutdown Cooling Piping Dose Rates Ec.c.5 3.11-51 Calculated 24 Inch ""
m2- - =
. c ^ i n3 Piping Dose Rates 3.11-5j Calculated 30 Inch Shutdown Cooling Piping Dose Rates gces derben Filfer 3.ll-5k Calculated 0 :n:h 2; :ter Et:-
' 77 r "'r'
- Dose Rates 1
Jnc41tc.lC 1
3.11-51 Calculated 10 2mmergwampewe Steam Exhaust Piping Dose Rates 4
3.ll-5m Calculated 12 Inch Steam Piping Dose Rates
([
3.11-6 Water Quality 1
3xviii
,.i DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT AND SYSTEMS FIGURES (Cont'd)
Figure No.
Title 3.9-6 Fuel Support Pieces 3.9-7 Jet Pump 3.9-8 Pressure Nodes Used for Depressurization Analysis 3.10-1 Typical Bench Board 3.10-2 Instrument Rack 3.10-3 Typical Local Rack 3.10-4 NEMA Type 12 Enclosure 3.11-1 Primary Containment Zones 3.11-2 Calculated Post-LOCA Bounding Primary
(
Containment Pressure Profile 3.11-3 Calculated Post-LOCA Bounding sessynsati' Prim CoMM Temperature Profile v
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3.11-4 m__r:u 3.11-5 Calculated Reactor Enclosure LOCA Temperature Profile 3.11-6 Calculated Control Structure LOCA Temperature Profile 3.11-7 Calculated Isolation Valve Compartment (El.217') HELB Temperature Profile
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3.11 ENVIRONMENTAL DESIGN OF MECHANICAL AND ELECTRICAL EOUIPMENT Engineered safety feature (ESF) systems, including the reactor protection system (RPS), are safety-related equipment installed in accordance with mechanical and electrical separation requirements and designed and qualified, with appropriate margins, to function properly in the following service environments:
For all normal and upset environmental design a.
conditions, including the maximum and minimum limits for temperature, pressure, relative humidity, and radiation (gamma and neutron), the equipment is required to perform its normal operational function and/or pass its periodic tests.
Otherwise, the equipment must remain in a safe mode available for operation (excluding maintenance activities, if the equipment is part of a mutually redundant system or standby equipment).
The normal and upset environmental requirements are specified in Tables 3.11-1 and 3.11-5.
b.
In addition to the normal and upset operational environmental design bases stated above, the safety-related ESF equipment is designed to perform its safety function during exposure to the post-accident environment present in its operational area and/or remain in a safe mode after its safety function is performed.
Environmental design criteria for the design of mechanical and o
electrical components of the ESF system and RPS conform to 10 CFR
,{
Part 50, Appendix A, General Design Criteria 1, " Quality Standards and Records"; General Design Criteria 2,
" Design Bases for Portection Against Natural Phenomena":
4,
" Environmental and g
Missile Design Bases"; 23, " Protection System Failure Modes"; 50, 3
" Containment. Design Basis"; and 10 CFR Part 50, Appendix B, o
section XI. "Icel...;. c' NUREG 0588, Interim Staff Position on Environmental Qualification of Safety-Related Electrical sf, Equipment, is currently in progress and w)E Ji 11 be n-n M
&%assed in
&c & don,miod Quob% t m Vgert.
A 3.11.1 EQUIPMENT IDENTIFICATION AND ENVIRONMENTAL CONDITIONS 3.11.1.1 Nuclear Steam Supply System (NSSS) Enoineered Safety Features and Reactor Protection System Equipment An ESF is a safety-related system that provides a safety function to prevent, limit, or mitigate the consequences of a design basis accident (DBA) that may cause major fuel damage.
An ESF includes the primary auxiliary systems of the safety system.
The identification, location, and accident environmental design bases 3.11-1
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2.
Total integrated radiation doses (TID) for 40 years are calculated for a 100% load factor and rated power at various locations during normal operation, as shown in Table 3.11-5.
b.
In addition to the normal and abnormal plant operation environmental requirements listed in a above, ESF components required to mitigate the consequences of a DBA and effect a safe shutdown are designed to remain functional during exposure to the applicable accident l
environmental conditions.
Applicable accident environmental conditions are those anticipated to follow a DBA that the component is intended to mitigate and are listed below.
1.
Components Inside Containment Specific values for temperature, pressure, relative humidity, and TID inside containment following a DBA are listed in Table 3.11-5.
The TID inside containment is calculated by assuming that 100% of
((g,c7g 4 the core noble gas inventory, 50% of the core halogen inventory, and 1% of the core solid fission
(
product inventory are releaseo.4 The duration of the DBA is assumed to be 180 days.
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2.
Components Outside Containment Specific values for temperature, pressure, relative humidity, and TID outside containment following a DBA are given in Table 3.11-5.
The TID outside containment is calculated by assuming that 50% of
- 15tsert, the core halogen inventory and 1S. of the core solid fission product inventory are in the emergency core l
lb) cooling system (ECCS) water atter a DBA.3 The duration of the DBA is assumed to be 180 days.
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l 3.11.2 QUALIFICATION TESTS AND ANALYSIS 3.11.2.1 NSSS Class IE Electrical and Mechanical Equipment Qualification All components of the Class IE equipment are qualified, either by test or analysis, consistent with Institute of Electrical and Electronics Engineers (IEEE) 323-1971.
Those components used in several systems, which can be located in different plant areas, are tested or analyzed for the worst environmental conditions in which they are required to function.
Consideration of their 3.11-4
-~~~
~ ~ - -
These source terms are consistent with those specified in NUREG-0588 and NUREG
<[The primary containment airborne dose calculations assumed that 50% of the 50%
(i.e. 25%) halogen release from the core plates out instantaneously, as assumed implicitly in Regulatory Guide 1.3, Rev. 2.
The airborne doses were calculated assuming source terms diluted by the primary contain-
-~
ment (drywell and wetwell) free volume.
These assumptions are consistent with those specified in NUREG-0737.
The beta doses and dose rates were calcu-lated assuming an infinite cloud geometry.
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post-accident airborne radiation doses were calcualted in accordance with NUREG-0737 and not specifically based on NUREG-0588.
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malfunction limits for critical parameters for different applications, where possible, is called for in the tpst procedures.
,, Systems containing Class IE components are analyzed to ensure compliance with IEEE 275-1971, paragraph 4.3, relating to the single failure criteria of IEEE 379-1972, and paragraph 4.4, relating to completion of protective actions.
l 3.11.2.1.1 NSSS Safety-Related Equipment Qualification All components of safety-related equipment are tested and/or analyzed to meet the requirements of 10 CFR Part 50, Criteria 1, 4,
23, and 50.
Satisfaction of Criterion 1 is achieved by reviews to assure that tests or analyses conform to the design, procurement, fabrication, and environmental qualification documentation.
The environmental requirements of Criterion 4 are addressed in this section, while considerations relating to i
missiles are addressed in Section 3.5.
The normal upset and abnormal postulated accident environments are shown in Tables 3.11-1 through 3.11-4 for Class IE. electrical component qualification to meet the requirements of Criterion 23 for protection system failure modes, which are addressed in Chapter 7.
The LOCA containment pressures and temperatures used for component tests and analyses to satisfy the requirements of criterion 50 and assure containment integrity are shown in Table 3.11-2.
I Section 8.1.6.1 discusses Regulatory Guide 1.30, relating to the installation and related quality assurance of controls and instrumentation; Regulatory Guide 1.40, relating to continuous duty safety-related motors inside the primary containment:
Regulatory Guide 1.63, relating to electrical penetrations; l
Regulatory Guide 1.131, relating to qualification of electrical cables, field splices, and connections.
The NSSS-supplied cable does not experience severe environmental
)
conditions, since it experiences the control room environment.
This cable is qualified as part of the power. generation control center (PGCC) floor section module.
The qualification information for the floor section module is contained in the PGCC NEDO-10466.
w e
Compliance with IEEE-323(1974) and Regulatory Guide 1.89 were not y design and qualification requirements for this plant.
Class IE k
-j equipment supplied by General Electric has been tested in order p
g to comply with IEEE-323(1971) criteria.
A program to evaluate L
- p -
contormance to sned
- M ---'nte of NUREG 0588, Interim Staff
,c W
Position on Environmental Qualification of, Safety Related Electrical Equipment, is
':r d===Iupment.
The results of that program will be hwww;.d ir.tc thM0th dscussed l',$
A p&c. &deonmCNoA $ a a lif g y & fe f.b i
3.11-5
% R e 5.R.S.2.2. b Yd)
.I Normal and maximum radiation exposures based on the above assumptions are presented in Table 3.11-5.
e Organic materials that exist within the containment are 1.dgntified in Section 6.1.2.
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IES PSAn Tksta 3.11-5 (cont'd)
(Pete 6 of SI geotes (cont'd)
(4)
First nsamher corresponde to maalmum IDCA/ lose of eentilation temperature. Second nianher corresponde to mentates Nigh Deergy Line greek temperatore e where applicable. Break identification to indicated as followes a.
pCIC eteam line break in RCIC piamp room b.
RPCI steam line break in NPCI pop room c.
HPCI stesen line break in isolation valve campertment d.
segv line break in puCU nonregenerative heat enchanger compartment e.
pWCU tine break in puCU pianp rorm f.
FestJ line break in puCU regenerative heet eschanger compartment g.
pWCU line break in puCU 3eolation valve compartment h.
Main steam !!ne break in main steam tonnel 1.
RMn steam line break in RRR compartment IOCA temperature profiles se a function of time are provided in Figure 3.11-3 through Figure 3.11-6.
Pur aroes eithout IOCA temperature profiles, aseme the maximise temperature laste 100 days. The isolation velve cuwperteent NEIA temperature profile as a function of time is provided in rigure 3.11-7.
Areas which have maalatum NEtA temperatures listed, but do not have NEIA temperature profiles, only contain components which will have completed their safety function once the bloudoen has ceased, which in att cases le significantly teos than one minute. De maalasse temperatures listed for the control structure are mesistas 1DCA temperatures. Senatetse temperatures resulting frcus other accidents will be evaluated later.
II!
Those roome which esperience Nigh Energy Line Break, identified by letters per note 4, will be subjected to 1000 relative humidity for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> af ter the start of the Righ Energy Line Break at which time the relative humidity w111 fait below 900 Pur the nors=1 primary contairement relative humidity, the miniesma relative hsenidity is provided instead of the everage relative humidity.
III The I4CA total integrated doces are for 100 doye. The beu doses and dose rates are conservatively W en infinite cloud geometry, and the doses for arese containing radioactive pipes are conservatively based on piping contact doses.
Dnees for specific components within these areas may be lower, depending on distence and opettet rotationehtye.
(7)
Primary Containment Cloud (See Table 3.11-Sa).
I8I (bntrol structure Cloud, Adjacent Piping shine (Dose ratee not tabulated because of toe Total Integrated Does (TfD)).
W SGTS Carbon Filter ($ee Table 3.11-Sb).
00)
Adjacent Cloud shine, Adjacent Piping Shine and SCTs Carbon Filter shine (Dooo rates not tabulated beesume of low TfD).
IW Control Structure Cloud and SCTS Carbon Filter Shine (Dose rates not tabulated because of low TID).
(13) secondary contairement Cloud (see Table 3.11eSe, UD 30* Shutdown Cooling Piping (see Table 3.11-5 )3 (14)
I 24* Shutdown Cooling Piping (see Table 3.14-5 )
USI h
19* Shwtdown Cooling Piping (see Table 3.It-S g UN 9
16* Shutdown Cooling Piping (see Tab %e 3.11-5 )
UII 6* Shutdown Onoling Piping (see Table 3.11-5')
(18) 9 16' ECCS Piping (see Table 3.18-5 )
U 'I I
14' ECCS Piping (see Teble 3.11-5 )
l (20) 6* ECr$ Piping (see Table 3.11-5')
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(20 12*HPCISteamSupplyPiping(seeTable3.11-5"g)
(
(22) 10' RCIC Steam Exhaust Piping (see Table 3.11-5 (23)
(see Table 3.11-5")d prR8 Cartwwi Pilter (34) 6* reenmbiner piping (see Table 3.11-5,
(25) This torne is located on the reactor enclosure roof.
(26)
The North Stack padiation pennitoring skxe temperature drope to 130*F after 6 doye (27) 24' fCC8 Piping (see Table 3.11-51)
[g, 28 I T1001550-01v
TABLE 3.11-5a 8
CALCULATED PRIMARY CONTAINMENT DOSE RATES 10 12 Gamma Dose Rates 15 TIME DOSE RATE INT. DOSE TOTAL 18 INT. HRS R/HR RADS RADS 19 i
.10E-01 1.07E+07
.00
.00 21
.50E+00 3.51E+06 3.16E+06 3.16E+06 22
.10E+01 2.60E+06 1.52E+06 4.68E+06 23
.20E+01 1.85E+06 2.20E+06 6.88E+06 24
.40E+01 1.23E+06 3.04E+06 9.92E+06 25
.80E+01 7.10E+05 3.79E+06 1.37E+07 26
.16E+02 3.66E+05 4.15E+06 1.79E+07 27
.24E+02 2.41E+05 2.39E+06 2.03E+07 28
.96E+02 7.17E+04 1.01E+07 3.03E+07 29
.24E+03 3.45E+04 7.323+06 3.76E+07 30
.72E+03 4.37E+03 7.00E+06 4.46E+07 31
.22E+04 2.56E+01 1.22E+06 4.58E407 32
.43E+04 6.56E+00 3.02E+04 4.59E+07 33 Beta Dose Rates 36 TIME DOSE RATE INT. DOSE TOTAL 39 INT. HRS R/HR RADS RADS 40
.10E-01 1.30E+08
.00
.00 42
.50E+00 4.48E+07 3.92E+07 3.92E+07 43
.10E+01 3.56E+07 2.00E+07 5.92E+07 44
.20E+01 2.68E+07 3.10E+07 9.02E+07 45
.40E+01 1.88E+07 4.51E+07 1.35E+0B 46
.30E+01 1.26E+07 6.20E+07 1.97E+08 47
.16E+02 8.00E+06 8.10E+07 2.78E+08 48
~
.24E+02 5.92E+06 5.53E+07 3.34E+08 49
.96E+02 2.22E+06 2.72E+08 6.05E+08 50
.24E+03 1.01E+06 2.21E+0B 8.26E+08 51
.72E+03 1.25E+05 2.03E+08 1.03E+09 52
.22E+04 3.00E+04 9.59E+07 1.13E+09 53
.43E+04 1.87E+04 5.16E+07 1.18E+09 54 55 20 Sk3
.n Rev. L7, 02/83 G
LGS FSAR TABLE 3.11-5b SGTS CARBON FILTER CALCULATED DOSE RATES TIME DOSE RATE INT. DOSE TOTAL INT. HRS R/HR RADS RADS
.10E-01 2.50E-03
.00
.00
.50E+00 1.00E+01 6.17E-01 6.17E-01
.10E+01 3.10E+01 9.47E+00 1.01E+01
.20E+01 7.47E+01 4.97E+01 5.98E+01
.40E+01 1.40E+02 2.08E+02 2.68E+02
.80E+01 2.10E+02 6.91E+02 9.58E+02
.16E+02 2.63E+02 1.88E+03 2.84E+03
.24E+02 2.81E+02 2.18E+03 5.02E+03
.96E+02 3.50E+02 2.26E+04 2.76E+04
.24E+03 4.51E+02 5.74E+04 8.50E+04-
.72E+03 2.30E+02 1.58E+05 2.43E+05
.22E+04 ~
3.41E+00 7.75E+04 3.21E+05
.43E+04 2.40E-03 1.01E+03 3.22E+05 l
l 20 S/83 Rev. 11, -0 2/8 3 O
TABLE 3.11-Se 8
CALCULATED SECONDARY CONTAINMENT DOSE RATES 10 12 Gamma Dose Rates 15 TIME DOSE RATE INT. DOSE TOTAL 18 INT. HRS R/HR RADS RADS 19
.10E-09 1.00E-10
.00
.00 21
.50E+00 2.49E+02 4.36E+00 4.36E+00 22
.10E+01 3.23E+02 1.42E+02 1.46E+02 23
.20E+01 3.93E+02 3.57E+02 5.03E+02 24
.40E+01 4.55E+02 8.47E+02 1.35E+03 25
.00E+01 4.46E+02 1.80E+03 3.15E+03 26
.24E+02 3.07E+02 5.96E+03 9.11E+03 27
.96E+02 1.87E+02 1.74E+04 2.65E+04 28
.24E+03 9.33E+01 1.94E+04 4.59E+04 29
.72E+03 6.40E+00 1.56E+04 6.15E+04 30
.43E+04 5.78E-02 4.85E+03 6.63E+04 31 Beta Dose Rates 34 TIME DOSE RATE INT. DOSE TOTAL 37 INT. HRS R/HR RADS RADS 38
.10E-09 1.00E-10
.00
.00 40
.50E+00 9.40E+02 1.57E+01 1.57E+01 41
.10E+01 1.39E+03 5.75E+02 5.91E+02 42
.20E+01 1.92E+03 1.64E+03 2.23E+03 43
.40E+01 2.50E+03 4.41E+03 6.64E+03 44
. 5E+ 0} l. 80E f BY 1.77E+04
([E)
.80E+01 3.03E+03
.24E+02 3.50E+03 5.22E+04 6.99E+04 46
.96E+02 3.35E+03 2.47E+05 3.16E+05 47
.24E+03 1.75E+03 3.55E+05 6.71E+05 48 2
1.01E+06 49
.72E+03 2.01E+02 3.44E+05 l
.43E+04 4.23E+01 3.66E+05 1.38E+06 50 l
51 20 S/$9 Rev. 47, 02/83 Q-
TABLE 3.11-5d 8
6 INCH RECOMBINER 10 CALCULATED PIPING DOSE RATES 11 13 TIME DOSE RATE INT. DOSE TOTAL 15 INT. MRS R/HR RADS RADS 16
.10E-09 7.53E+04 0
0 18
.50E+00 2.95E+04 2.44E+04 2.44E+04 19 r
l
.10E+01 2.25E+04 1.29E+04 3.73E+04 20
.20E+01 1.54E+04 1.87E+04 5.61E+04 21
.40E+01 9.75E+03 2.47E+04 8.08E+04 22
.80E+01 5.57E+03 2.99E+04 1.11E+05 23
.24E+02 1.82E+03 5.36E+04 1.64E+05 24
.96E+02 4.19E+02 6.86E+04 2.33E+05 25
.24E+03 2.08E+02 4.34E+04 2.76E+05.
26
.72E+03 3.34E+01 4.59E+04 3.22E+05 27
.43E+04 8.80E-01 2.02E+04 3.42E+05 28 31 8
e Rev. 17, -02/8 3 d) 1
TABLE 3.11-Se 8
6 INCH ECCS 10
[
CALCULATED PIPE DOSE RATES #
13 TIME DOSE RATE INT. DOSE TOTAL 16 INT. HRS R/HR RADS RADS 17
.10E-09 5.79E+04
.00
.00 19
.50E+00 4.18E+04 2.47E+04 2.47E+04 20
.10E+01 3.57E+04 1.93E+04 4.40E+04 21
.20E+01 2.77E+04 3.15E+04 7.56E+04 22
.40E+01 1.97E+04 4.70E+04 1.23E+05 23
.80E+01 1.32E+04 6.49E+04 1.87E+05 24
.24E+02 5.91E+03 1.45E+05 3.32E+05 25
.96E+02 1.91E+03 2.55E+05 5.87E+05 26
.24E+03 1.12E+03 2.13E+05 8.00E+05 27
.72E+03 4.42E+02 3.50E+05 1.15E+06 28
.43E+04 7.05E+01 7.28E+05 1.88E+06 29
/
0 E LETE __
0 3
/
's-
/
~
i ut wn ool g
in do ra sc be et in m
i i
he i
E pin dos rat b
f or 25 /
36 i
o 20 3*/B3 Rev. 17 -02/83 - h 7
TABLE 3.11-5f 8
14 INCH ECCS 10
?
CALCULATED PIPING DOSE RATES 11 13 TIME DOSE RATE INT. DOSE TOTAL 16 INT. HRS R/HR RADS RADS 17
.10E-09 1.15E+05
.00
.00 19
.50E+00 8.30E+04 4.92E+04 4.92E+04 20
.10E+01 7.07E+04 3.84E+04 8.75E+04 21
.20E+01 5.49E+04 6.25E+04 1.50E+05 22
.40E+01 3.89E+04 9.29E+04 2.43E+05 23
.00E+01 2.58E+04 1.28E+05 3.71E+05 24
.24E+02 1.14E+04 2.83E+05 6.53E+05 25
.96E+02 3.62E+03 4.89E+05 1.14E+06 26
.2.4E+03 2.13E+03 4.05E+05 1.55E+06 27
.72E+03 8.54E+02 6.70E+05 2.22E+06 28
.43E+04 1.38E+02 1.41E+06 3.63E+06 29 30 l
i I
e M
l 20 S /83 Rev. 1-7,-02/83 6
TABLE 3.11-5g 8
16 INCH ECCS 1
[
CALCULATED PIPING DOSE RATES' ;'
TIME DOSE RATE INT. DOSE TOTAL 16 INT. HRS R/HR RADS RADS 17
.10E-09 1.24E+05
.00
.00 19
.50E+00 8.93E+04 5.30E+04 5.30E+04 20
.10E+01 7.60E+04 4.13E+04 9.42E+04 21
.20E+01 5.90E+04 6.71E+04 1.61E+05 22
.40E+01 4.18E+04 9.98E+04 2.61E+05 23
.80E+01 2.77E+04 1.37E+05 3.98E+05 24
.24E+02 1.22E+04 3.03E+05 7.01E+05 25
.96E+02 3.85E+03 5.21E+05 1.22E+06 26
.24E+03 2.27E+03 4.30E+05 1.65E+06 27 l
.72E+03 9.12E+02 7.15E+05 2.37E+06 28
.43E+04 1.48E+02 1.51E+06 3.88E+06 29
/ -77/ pelE 75~
U3 v
l 1
s dow oo ~ g pi d
r es n
de tr' b
.u l lyi h
6 h
CS 1pi d
er es a c_
of
.425 l
l 20
$/B}
[3)
Rev. 14 -02/83 7
l TABLE 3.11-5h 8
18 INCH SHUTDOWN COOLING 10 t
CALCULATED PIPING DOSE RATES 11 13 TIME DOSE RATE INT. DOSE TOTAL 16 INT. HRS R/HR RADS RADS 17
.10E-09 s.52 4994E+08 f
.00
.00 19
.50E+00
't.95 M99E+05 V I&O 4 44E+05 Y s 00 4,GitE+ 05 Y 20
.10E+01 r.0f h48E+05 V V. 37 5,6eE+ 0) V 4.97 S,4GE+ 05 V 21
.20E+01 G.z.3 h46E+05 4 7.so 5,44E+07'/
/.71 v.-9tE+0$5 22
.40E+01 v.4.2tettE+08 Y
/. 05 S,44E+ 05 J.77 %44 E+ 0 6 5 23
.80E+01 J.424 44E+05'/
/.V.f h44E+ 0i f 4/. 2 / &,46 E+ O f 5 24 l
.24E+02 f.2F h44E+0pV
.519 tv69E+0s E
- 7. 59 WE+ 0F #
25
.96E+02 v.013,44E+ 0# 3 s.y7 h44E+0ir f.2fr heeE+0F G 26
.24E+03 a..s7 h49E+043 v.s/4,4GE+0iS t.7.5 h46E+0JG 27
.72E+03 4.59 4 46E+0) 2 7.504,46E+ 08 f
.2.49 %44E+ 07 6 28
.43E+04 f.Si 4,64 E+ 03 2
/.59 ht4E+01 &
V.cF&,44E+0FG l
20
$/83 Rev. A -02/83' -3
TABLE 3.11-51 8
CMS 24 INCH N O
CALCULATED P2 PING DOSE RATES ***
13 TIME DOSE RATE INT. DOSE TOTAL 16 INT. HRS R/HR RADS RADS 17 l
.10E-09
/. V7 4,44E+ 08 f
.00
.00
.50E+00
/.0fe,49E+ 05 6.Ju Eve #E+0) Y 4 2G 4,47E+0gt'
- 20 B'.f i,6 4 E + 0 8 Y 4.Ff 4,49E+0p V
/. / / 6,4F E + 05 21
.10E+01 9
.20E+01 6.936 44E+0)V
?.9 / 6,46E+ 0 F V
/.44 M46E+0(S 22
.40E+01 Y.406,44E+05V l.17 9,49E+ 05 3.07 4,44E+ 0s.r 23
.80E+01 J 2*/4,48E+0py
/.ko 4,46E+0$ 5 V.M' M E+0fr 24
.24E+02
/.Y/ 4,+9E+ 0 5 V J.53 4,+9E+ 0p f I.26 MME+0ff 25
.96E+02 V.404,94E+ 0( 3 E.H Pr@5E+075
/ 42 4-46E+0f &
26
.24E+03 J.57 4,4eE+ 04 J V.93 M E+095
/.9/ M E+0/&
27
.72E+C3
/.cre,4eE+03 c.206 44E+066'
.p.73 +:9tE+ 0/&
28
.43E+04
/ 7/ WE+0$ 2
/,7'/ 6 44E+07 &
4.V'I 4,46E + 0/ &
2 pi ose t
can e
eter ne y
i
[32 4
ch ut n
li pi ose te y
ac r
33 Y
25 DGt2TE 35
{
l 20 Tb3 R e v. 4 h - 0 2 / 6-3 A
TABLE 3.11-5j 8
30 INCH SHUTDOWN COOLING 10 CALCULATED PIPING DOSE RATES 11 13 TIME DOSE RATE INT. DOSE TOTAL 16 INT. HRS R/HR RADS RADS 17
.10E-09
/,57 6,42E+ 0p 5
.00
.00
.50E+00
/./2 9,4GE+ 05 4.6f WE+05 V te.G5 b44E+ 05 y 20
.10E+01 4df h.49E+0p V s,/5 4,44E+0p Y
/ / P 9,44E+ 05 21
.20E+01 7.3Y M E+0 V r.37 4,44E+ Of V J.c2 h 4GE+0i f
,t2
.40E+01 E.19 4,M E+0 V t.23 h44E+0J E
- 3. 2f 9,44E+ 06 i 23
.80E+01
.3.V2 +re9E+ 0 V
/.70 2 43E+08 5~
V.95~4,M E+0i f 24
.24E+O2 1.VF 4,44E+ 0) V J.70 4,+ilE+ 0i.s~
r./,G h44E+ 0i f 25
.96E+02 4.57tr44E+0p3 6.24 b4GE+0F f
/.50 h44E+ 0f G 26
.24E+03 J.72 4,4GE+ 0p 3 f./f4,44E+0A f J.0/ h44E+ 07 6 27
.72E+03
/.// 95-)t E+ 03 J'.51 h44E+075~
J.r7an4tE+0f?
28
.43E+04
/.r0 +r&f E+ 0/ 2
/,t'[ b4.LE+ 0F &
v.7/ FrM E+0/ G 19) 30 l
%)
$/$$1 Rev. I h-02/8 3-
[
a.
s 4.a-..
TABLE 3.11-5k 8
CALCULATED RERS CARBON FILTER DOSE RATES 10 12 TIME DOSE RATE INT. DOSE TOTAL 15 INT. MRS R/HR RADS RADS 16
.10E-01 2.50E+03
.00
.00 18
.50E+00 7.99E+02 3.09E+01 3.09E+01 19
.10E+01 2.08E+03 6.70E+02 7.01E+02 20
.20E+01 4.20E+03 3.02E+03 3.72E+03 21
.40E+01 6.64E+03 1.07E+04 1.44E+04 22
.80E+01 8.90E+03 3.09E+04 4.52E+04 23
.24E+02 1.11E+04 1.60E+05 2.05E+05 24
.96E+02 1.18E+04 8.25E+05 1.03E+06 25
.24E+03 1.45E+04 1.89E+06 2.92E+06 26
.72E+03 7.40E+03 5.07E+06 7.99E+06 27
.43E+04 7.69E-02 2.32E+06 1.03E+07 28 29 l
l l
l 20 fl$3 Rev.
14,- 02/83
~
10 INCH RCIC STEAM EXHAUST 10
?
CALCULATED PIPING DOSE RATES 11 13 TIME DOSE RATE INT. DOSE TOTAL 16 INT. HRS R/HR RADS RADS 17
.10E-09 2.06E+05
.00
.00 19
.50E+00 6.02E+04 5.93E+04 5.93E+04 20
.10E+01 3.41E+04 2.30E+04 8.23E+04 21
.20E+01 1.31E+04 2.19E+04 1.04E+05 22
.40E+01 2.56E+03 1.29E+04 1.17E+05 23
.80E+01 1.40E+02 3.33E+03 1.20E+05 24
.24E+02 3.92E-03 2.14E+02 1.21E+05 25 26 l
l 1
1 1
l l
l l
l l
20 ffb3 Rev. H M 2/83-l
TABLE 3.11-5m 8
l CALCULATED 12 INCH HPCI STEAM SUPPLY PIPING DOSE RATES 10 12 TIME DOSE RATE INT. DOSE TOTAL 15 INT. HRS R/HR RADS RADS 16
.10E-09 4.62E+06
.00
.00 18
.50E+00 2.25E+05 7.27E+05 7.27E+05 19
.10E+01 2.14E+04 4.33E+04 7.71E+05 20
.20E+01 2.28E+02 4.67E+03 7.76E+05 21
.40E+01 3.50E-02 5.20E+01 7.76E+05 22 23 20 1/85 Rev. 44--02 /8 3 '
J'
I ZONE 1 6L. 3 8 9
- I hi i
B'r
}Vi
- f ZONE 3 l
'I 4.p-l'*f r
b.,
illln'l
- ?
I e
g i
i w
et..u6'
..l
,__ g I
,a l
l
?f4 l
N l
2 i
2ONE 3
.i ZONE 4 ZONE 5 I
s..
M i
$*_ _4 S? _'4
_J_______
~ 6 C.I C,
l ZONE 6 4
41 LIMERICK GENERATING STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT PRIMARY CONTAINMENT ZONES FIGURE 3.111 h2O 83
e
- ~ ~ '
~
so -
J iG 44 40 37 PSIG t
t =30 SEC E 30 E
~
E
$wg 20 17 PSIG t =t 6 HRS to 10 PSIG t =t 36 HRS 4 pggg t = 11.6 DAYS 0
1 MIN 6 HRS 24 HRS 48 HRS 3 DAYS 11.6 DAYS 180 DAYS TIME LIMERICK GENER ATING STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CALCULATED POST LOCA BOUNDING PRIMARY CONTAINMENT PRESSURE PROFILE F1GURE 3.112 If.4/. E O I!83
e m
e m 40*F.
l 3
i QO*F
~
3 > R$
[
250 l
l 212'F 200 t=6 HRS 196 F t = 12 HRS 184 F 175oF t = 24 HRS 158'F t = 36 HRS t = 48 HRS
\\
t = 3 DAYS t = 11.6 DAYS 122'F
\\ 112*F f
100 O.
12 HRS 24 HRS 2 DAYS 4 DAYS 11.6 DAYS 23.2 DAYS [ 180 DAYS
^
TIME _
l 8
LIME RICK GENER ATING STATION i
UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT PAinsV N g g/JrnENT CALCULATED POST LOCA BOUNDING 96MMWEtt TEMPERATURE PROFILE FIGURE 3.113 bD 3
f l
V.
I
(
i
=
.~....
225 212'F I
l i
t=12 HRS 200 l
24 HR$
186'F C
t = 36 HR$
77'F t = 48 HRS 159'F 150 t = 3 DAYS L
t = 11.6 DAYS 12
- g
= 212 DAYS 33 y
/
i i
e i
i e
i 100 0 1
2 F
11.6 23.2 [
81 180 TIME (DAYS)
M o.ooo me <.
LIMERICK GENER ATING STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT
'C E." ^,0 7 L ^^.^.
_a m,. m.... a s.s.
FIGURE 3.114 h 24 f[33
hj l
i l
!I l'
1 f The app!! cant must demonstrate why allowing a pressure greater than minus l
l
' ~ i! 0.231nch water in the common refueling area fo!!owing a LOCA is' acceptable l
j' O.e., no leakage or trypass leakage paths from the primary containment to the common refueling area, no LOCA impact on fuel storage facilities). (Note: This is a new issue resulting from the SCTS design change documented lis FSAR T Revision 15J
).
Rswa-
._ _- t T g, m,,e 4 &Iwb!. /an sA"y'll rd
~
^~
es/ap si. fyan %/sp psas
&m }
- ((,
-se l ~~ fJ A pwnay esnt'anwsaF7o' M wnmar n.., 4 4 j x s e m 4
- 1. _ _
l __ _
!. olfacted.
I o
1 _-. -..
l i
i, 4.____.._.
)
l i
ll l
j_..____.._.
I it i
t___.____.___
q..___.._.__-._.
t j ___ __. _ _ _ _ _ _ _ _ _ _ _ _ _ _.
1 i
(n _ _ - _.. -.
i il h
l l
1
-, _ ~.
OUESTION 480.22 (Section 6.2.3)
FSAR Section 6.2.3.2.1, page 6.2-40, states "An analysis of the post-LOCA pressure transient in the secondary containment will be performed to determine the length of time following isolation signal initiation of the SGTS that the pressure in the secondary l
containment would exceed minus 0.25 in, wg."
Provide the results of this analysis of the pressure and temperature response of the secondary containment to a loss-of-coolant accident (LOCA) occurring inside the primary containment, and describe specifically how each of the guidelines of SRP Section 6.2.3 Item i
II.1 has been followed.
RESPONSE
l Section 6.2.3.2.1.has been changed to provide the results of the post-LOCA secondary containment pressure transient analysis.
The LOCA radiological analyses in Chapter 15 have been changed to i
account for the radiation released from the secondary containment during the time that the pressure exce'eds minus 0.25 in wg.
l i
nhMMiM ow ho b
$YaMedLM audd *Ms, A da.ked.M____ __
._h twitu3 % bue, pfpvmtd _b_ide.wkh yd.wWA.WWp.__._ _
pO. M _ hema al b k
g C#VLOM_ car $_a l;w&wy CmhaA. - n ou.ig o-r bJCYttu3 ftSR.$klLCL Aho.__k UMO Cho.AA.}t.S \\dAIdN. AAA*hWf4 b k _ Vio.h o12.a p. p M. U dfidt y.
a._Avwk ga.&.- p %_ on.tbr_.u.an. % %,
f4. M.ke V JLM M _ W M M Ack.
. _ _. _ __ b. _ N O V W A. d c.loSA.c(\\Ja.INC.S aw h Y~AAckey uJdi._. _ __
dbWVoMLV dfU MW \\.Mtirt Oddle.d.
_ _ _ _... Med't C, _k
. CWC,
]4 m = + A h o. g s w, h 2 g u a p w Tdvsi.cd TelycaMows baartg bt A suce.do.vg _.
_-. p fpA.ve\\wer. par aq ak a. vu.gaW(, Mwev puxt g _
!.o.25 6.uw. _ _
_ _ _.H u
480.22-1 Rev. 4Gmsif8F
.e-
--r
- -.,-, _-,._,,._+- -_
__-,,---m
l 4p b
! h*m E.
Regardin the identification of bypas leakage paths, C55 has thre( remairung, __ _
_ Pl con = ems:g(openItem)
The app!icant has not adequately demorotrated why it is realistic to a.
anume that a water seal at a pressure greater than the contalnment -
accident pressure and lasting at least 30 days could be maintalned in the feedwater line by water from the condensate storage tank following a
'feedwater line break Inside containment,
- b..The app!! cant has not demonstrated that the requirements of a closed
- ~~,
l
' system are met for the systems inside containment to stJch the
~ ~~~
recirculation pump cooling water supply and return lines and the drywell chilled water supply and return lines connect. The applicant's response to NRC Question 480.26 Part a has not resolved this open item. _ _ _ _._..._ ___
c.
C5B has bedn unab!e to confirm the presence of a vent !!ne to the secondary containment located before two block valves and the l
secondary containment in the nitrogen line to the TIP Indexing
.____t. _, mechanism.- -
2--
h-,--
-+--m-*--
e+~- = * -+
/40.
-~
^
s) Ashk izw./ 4 /m s4yd h af,,im44
~
[
& A, i/ 5 ses & di 4 m eine ;( M y,h/.14 an d # mansV fy A a+
ish sh/p W~
a 14 Aedede & db s,Q,4, A g;f.~
spik tsnldmmend.
~
2()
ib.Itsb M
lh Madbdelm $b A s h u l " l M = ; M Tl E
<aisa~d 6sa,,ed
['
7b ? odw/ eda
/4 gne A as/6 /.c s) fadh s.z.s2.1 4 ta skye/ / /~s&d af a ejsdisd o ?,aad d,sadask 4
x Asu d 4 & a svn u t,;,,,,. a$ a
- zo b W!! k-f rpe ljh (a.vhed. %ct.A4 eve, o#4 (dh.hd g G4 wd1 % M b. U 'IS I
aho b TAri.vd. l o rafhd b. *a.c.keA ely.
' whi t,k hoa e
g x
l
- )
The secondary containment design data are in Table 6.2-14.
j 6.2.3.2.2 Secondary Containment Isolation System l
Isolation dampers and the plent protection signals that activate the secondary containment isolation system are described in Section 9.4.2.1.3.
6.2.3.2.3 Containment Bypass Leakage Upon receipt of a reactor enclosure isolation signal, the reactor enclosure recirculation system (EERS) and the SGTS are automatically activated and~begin to process all air flow streams from the reactor enclosure ventilation system.
Therefore, if a (pCA occurs, radioactivity that exfiltrates the steel-lined primary containment or piping systems containing radioactive fluids is collected and passed through the RERS and SGTS as described in Section 6.5.
The potential paths by which leakage from the primary containment can bypass the areas serviced by the SGTS have been evaluated.
4, Table 6.2-15 identifies all primary containment penetrations, the q
termination region of all lines penetrating primary containment, )g and the bypass leakage barriers in each line.
It has been e
i 3
determined that no potential bypass leakage paths exist f:: th: y entir: :p:;trum ;f LOCA:
- t f;; ; f;;da;tcr linc br;ak incid;
';;nt:ir :nt. $A water seal cannot be maintained in the broken feedwater line by the feedwater fill system (Section 6.2.3.2.3.2) for the case of a feedwater line break inside containment.
For this case, containment leakage may travel past the broken feedwater line's containment isolation valves into the portion of the feedwater line located in the turbine enclosure.
However, a water seal in this portion of the feedwater line would r;;licticall; bc
- pected to be maintained by water from the condensate storage tankf tThcr f:rt, n: hyp2rr Ir2hage ir p;;tul:ted te re:05 the,erfircr en n g g g ;.
Qm W,3.2.51 When designating the termination region, if either the system line that penetrates primary containment or any branch lines connecting to it penetrate the secondary containment, the termination region is listed in Table 6.2-15 as outside secondary containment (OSC).
The types of bypass leakage barriers employed by these lines are:
1.
Redundant primary containment isolation valves 2.
Closed seismic Category I piping system inside containment 3.
A water seal maintained for 30 days following a LOCA f
6.2-43 Rev. 15, 12/82 t
l
~.
-4m__
.m.m._
m
-.a_
m.
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The line beyond the outboard primary containment isolation valve is vented to secondary containment by use of a vent-line located upstream of the two block valves.
5.
A leakage collection system is provided.
6.
The line contains a temporary spool piece that is removed during normal operation and replaced by blind flanges so that any leakage through the flange is into secondary containment.
\\
Type 1 leakage barriers are considered to limit but not eliminate bypass leakage.
Leakage barriers of types 2 through 6 are considered to effectively eliminate any bypass leakage.
J Leskage from those lines terminating in the reactor enclosure is collected during the LOCA because the reactor enclosure is l
restored to and maintained at subatmospheric pressure and all exhaust is processed by the RERS and SGTS during these modes I
(Section 6.5).
Therefore, lines terminating within the reactor enclosure are not considered potential bypass leakage paths.
Lines penetrating primary containment are isolated following a LOCA as described in Section 6.2.4.
All containment isolation valves and penetrations are designed to seismic Category I T
requirements.
1 l
The prinary containment and penetration leakage is monitored during periodic tests as discussed in Section 6.2.6.
Those penetrations for which credit isetaken for water seals as a means of eliminating bypass leakage (Table 6.2-15) are preoperationally leak-tested with water and Technical Specification leakage rates are given as water leak rates.
6.2.3.2.3.1 Water Seals In each case where water seals are used to eliminate the potential of secondary containment bypass leakage, a 30-day water seal is assured because either a loop seal is present or the water for the seal is provided from a large reservoir.
The water seals for all of these lines will be maintained at a pressure greater than the peak containment accident pressure.
Each of the water seals listed in Table 6.2-15 is discussed below (some l
penetrations may be listed more than once due to the presence of l
multiple types of water seals).
a.
Penetrations 9A & B and 44.
The feedwater fill system q)
(Section 6.2.3.2.3.2) is used to maintain a water seal
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b.
Penetrations 204A & B, 207A & B, 208B, 210, 212, 215, 216, 217, 226A & B, 235, 236, 238, 239 and 240.
The lines associated with these penetrations all penetrate the wetwell above the suppression pool water level and terminate at least 4 feet below the minimum suppression pool water level.
A 30-day water seal is therefore assured on the submerged portion of line.
c.
Penetrations 13A & B, 16A & B, 17, 39A & B, 45A-D, 205A
& B, and 225.
Piping connected to these penetrations is l
normally full of water and will be kept full after a LOCA due to operation of the ECCS and/or safeguard piping fill system.
The suppression pool is the water source for the ECCS and fill system, and therefore a 30-day water supply is assured.
d.
Penetrations 203A-D, 206A-D, 209, 214 and 237.
The lines associated with these penetrations all penetrate the wetwell at least 11 feet below the minimum water level of the suppression pool, and therefore a 30 day water seal is assured.
e.
Penetrations 231A & B.
The line to the containment isolation valves from the drywell ficor drain sump is C-maintained full of water by an elevation difference between the sump and the valves.
The line to the containment isolation valves from the drywell equipment drain tank is maintained full of water by an elevation difference between the tank and the valves.
f.
Penetrations 10, 11, 12, 44, 228D and 241.
Li'nes associated with these penetrations that pass through the secondary containment boundary and take credit for water seals are provided with loop seals inside secondary containment,'which eliminates the possibility of bypass leakage.
g.
Penetration 14.
The minimum piping height inside primary containment of the RWCU supply,line that branches off the recirculation loop is at El 267 ft.
The primary containment penetration is at fl. 297 ft and the RPV penetration is at El. 280 ft.
This elevation i
difference ensures that a water seal is maintained in l
the line from the RPV to the containment isolation valves.
The RWCU supply branch line that connects to the bottom of the vessel is normally full of water, and the water will be maintained in this line because it connects directly to, and below, the vessel.
h.
Penetrations 37A-D and 28A-D.
The CRD insert and
(
withdraw lines are normally full of water.
A water seal will be maintained in these lines after a LOCA due to i
6.2-44a Rev. 15, 12/82
Qhg LGS FSAR the elevation difference between the containment
'h penetrations (El. 265 ft) and the connections to the control rod drives (El. 215 ft).
6.2.3.2.3.2 Feedwater Fill System The feedwater fill system prevents the release of fission products through the feedwater containment isolation valves after a LOCA by providing a water seal downstream of the valves.
6.2.3.2.3.2.1 Safety Design Bases The feedwater fill system is designed with sufficient capacity and capability to prevent leakage through the feedwater lines under the conditions associated with the entire spectrum of LOCAs except for a feedwater line break inside containment.
The feedwater fill system conforms to seismic Category I requirements.
Quality group classifications are shown in Table 3.2-1, Item XI.A.
The system meets the intent of Regulatory Guide 1.96, where applicable.
The feedwater fill system is capable of performing its safety function considering the effects resulting from a LOCA, including missiles that may result from equipment failures, dynamic effects
'y associated with pipe whip and jet forces, and normal operating
../
and accident-caused local environmental conditions consistent with the design basis event.
Furthermore, any portion of the feedwater fill system that is quality Group A and is located outside the primary containment structure is protected from missiles, pipe whip, and jet force effects originating outside the containment so that containment integrity is maintained.
The feedwater fill system is capable of performing its safety function following a LOCA and an assumed single active failure.
The feedwater fill system is designed so that effects resulting from a single active component failure do not affect the integrity or operability of the feedwater lines or the feedwater containment isolation valves.
The feedwater fill system is capable of performing'its safety function following a loss of all offsite power coincident with a postulated design basis LOCA.
The feedwater fill system is designed to prevent leakage from the feedwater lines consistent with maintaining containment integrity for up to 30 days.
The feedwater fil) system is manually actuated and is not required to be actuated sooner than 30 minutes after a LOCA.
}
Rev. 15, 12/82 6.2-44b
j mS nu TABLE 6.7-15 (P:ge 1 cf 5)
EVALUATION OF POTENTIAL SECONDARY CONTAINMENT BYPASS LEAKAGE PATES CONTAIMMElfr TERMIM4 TION BYPASS IAARAGE POTENTIAL BYPASS PENETRATION SYSTEM REGION (sa BARRIERStas pgTN 1
Equipment access door ISC Double O-Ring No 2
Equipment access door and ISC Double O-Ring No personnel lock 3A Main steam (MS) line D flow ISC No instrumentation 3B Inst gas supply OSC 1,4 No l
3C HPCI steam flow inst ISC No 3D MS line A flow inst ISC No 3
3D Instrument gas supply OSC 1,4 No l
4 Head access manhole ISC Double 0-Ring No 5
Spare 6
CRD removal hatch ISC Double 0-Ring No 7A-D Primary steam OSC 1,5 No 8
Primary steam line drain OSC 1, 4 No 9ASB Feedwater OSC 1,3 No(88/d 10 Steam to RCIC turbine OSC 1,3,6 No I
11 Steam to HPCI turbine OSC 1,3,6 No 12 RHR shutdown cooling supply OSC 1,3 No i
13A&B RHR shutdown return OSC 1,3 No I
14 RWCU supply OSC 1,3 No 15 Spare j
16ASB Core spray pump discharge OSC 1,3 No 17 RPV head spray OSC 1,3 No 18 Spare 19 Spare No 20A RPV level inst ISC 20A LPCI AP inst ISC No 203 LPCI AP inst ISC No 20B RPV level inst ISC No 21 Spare 22 Drywell pressure inst ISC No 23 Closed cooling water supply OSC 2
No 24 Closed cooling water return OSC 2
No 25 Drywell purge supply OSC 1,4 No 26 Drywell purge exhaust ISC No 27A Instrument gas supply OSC 1,4 No l
27B HPCI flow inst ISC No Recirc loop sample ISC No 28A
29A Drywell He/Os ISC No No 28B LPCI AP inst ISC 28B-Drywell air sample ISC No 29A PPV flange leakage inst ISC No No 29B Core spray AP inst ISC No 30A NS line D flow inst ISC No 30B Drywell pressure inst ISC No 30B MS line C flow inst ISC Rev. 16, 01/93
LG3 FSAR TABLE 6.2-15 (Cont'd)
(PIge 2 Cf 5)
C3NTAINMENT T5tMINATION BYPASN LEAKAGE POTENTIAL BTPASS PENETRATION SYSTEM REGION (l9 BARRIERS (89 PATE No 31A8B Jet pump flow inst ISC No 32AEB Jet pump flow inst ISC 33A Pressure above core plate inst ISC No 334 Pressure below core plate inst ISC No No 33B RCIC steam flow inst ISC No 34A MS line C flow inst ISC No 34B Recirc flow inst ISC
-1[
M 35A Inst gas to TIP indexing mechanism 03C NO No 35C-G TIP drives ISC 36 Spare 37A-D CRD insert OSC 1,3 No 3 8 A-D CRD withdraw OSC 1,3 No 39A8B Drywell spray OSC 1,3 No No 40A,B6C Jet pump flow inst ISC No 40D Pressure below core plate inst ISC No 40E Drywell pressure inst ISC No 40F RCIC steam flow inst ISC 40F Inst gas suction OSC 1,4 No 40G ILRT data acquis system OSC 1,6 No 40H Instrument gas supply OSC 1,4 No j
No 40R Recirc pump cooler flow inst ISC No 41 LPCI AP inst ISC No 41 PWCU flow inst ISC No 42 Standby liquid control ISC No 43A Recirc loop A AP inst ISC No 43A Recirc pump seal pressure inst ISC No 43B Main steam sample ISC 44 CRD/RWCU return OSC 1,3 No 45A-D LPCI OSC 1,3 No 46 Spare No 47 RWCU flow inst ISC No 48A RPV level inst ISC No 48A Core spray AP inst ISC No 48B RPV level inst ISC No 49ASB MS line A&B flow inst ISC No SOA Drywell pressure inst ISC No SOA Recire flow inst ISC No 50B Pecire pump seal pressure inst ISC No SOB Pecirc pump cooler flow inst ISC 51A Recirc line flow inst ISC No No 51 B.,
Jet pump flow inst ISC No 52A -
MS line B flow inst ISC No 52B Recirc line flow inst ISC 53 Drywell chilled water supply OSC 2
NO 54 Drywell chilled water return OSC 2
No 55 Dryweli chilled water supply OSC 2
No 56 Drywell chilled water return OSC 2
No Rev. 16, 01/93
s' LG3 FSAR TABLE 6.2-15 (Cont'd)
(P;ge 5 cf 5) r CONTAINMENT TERMINATION-BYPASS LEAKAGE POTENTIAL BTPA88 PENETRATION SYSTEM REGIONC43 BARRIERSCa3 paygg
}
i i
(*3 The termination regions are: ISC - Inside Secondary Containment l
Osc - ountside secondary containment j
(83 The bypass leakage barriers are defined as follows to= section 6.2.3.3.3):
1.
Redundant primary containment isolation valves t
2.
Closed piping system inside containment ll 3.
A water seal maintained for 30 days following a IDCA 1
4.
Me line beyond the outboard primary containsHytt isolation valve is vented I'
to secondary containment by use of a vent line located between two block valves and the secondary containment.
l 5.
A leakage collection system is provided 6.
The line contains a temporary spool piece that is removed during normal operation and ' replaced by blind flanges so that any leakage through the flange is into secondary containment.
as) The feedwater fill system will provide a water seal in the feedwater lines for all line breaks other than a feedwater line break inside containment. 4 l
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___.__ _ _ _ _ Q kua. \\O h Diverse exmtainment isolation signals G.e., reactor wesnel leved trip and high drywell _.
pressure) are required to automatically isolate the nonessenehd main steam drain, lines.
_ ! main steam sample, recirculation loop sample, and RWCU system supply (open item)
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adequate te accour,t for instru ent errer.
Any prep sed values greater than 1 pst will require detailed justification.
Applicants for an operating li:ense and operating plant licensees that have operated less than one year shculd use pressure history data frot si-ilar plants that have cperated more than one year, if possible, to arrive at a ran17pm centainrent setpoint pressure.
(7)
Sealed-closed purge isolation valves should be under administrative control to assure that tney cannot be ir. advertently opened.
Ad.n:strative control includes F.echanical devices to seal er leek the valve closed, or to prevent power from being supplied to the valve operator.
Checking the valve position light in the control roo. is an adequate nethed for vertfying every 24 hoars that the purge valves are closed, s
Response
A description cf co pliance with each Positien and Clarification is provided below.
Position (1), Clarification (1-The containment isclation syster des gn has been reviewed for corpliance with SRP f.2.4 regardir.g diversity in the paraxeters censed for the initiation of containrent isolation.
Section 6.2.4 and Table 6.2-17 identify all contain ent isolation signals provided.
There are eleven valves classified as r.onessential that do not receive diverse containrent Isolatten s.gnals.
Two valves on the feedwater lines (HV-109A, HV-109B) are norr. ally closed and will be opened only for startup of the feedwater system before the contrcl rods are withdrawn.
l The RCIC vacuur. purp discharge line is provided with e stop-check valve (HV-FCO2i to prevent flow fro-the containment.
A renote manually actuated retor : operator ensures the long-term positive closure of the stop. check valve.
This arrangement ensures that the essential'RCIC purp-turbine will be ready to operate in the event of a reactor vessel isolation occurrence accorpanied by loss of feedwater flow.
5 2.
The recirculation pump cooling water supply and discharge g
isolation valves (HV-136, HV-107) and the drywell chilled r
water isolation valves (HV-122, HV-123, HV-128, HV-129s 2.
have provisions for remote ranual isolation consistent with 5
GDC $7.
Closure of these isolatien valves is undesirable s
i unless the cooling water lines have failed.
?
S Rav. 16,-01/83 1.13-38b j
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LGS FSAR The HPCI and RCIC stea supply line warrup valves (HV-F100, HV-F076, respective 3ys are provided with appropriate iso 3ation sige.als to se: ore the line when system isolatien AP is required.
There is no adverse consequence associated with the valve opening or leaking while these systems are in operation.
Position (21, Clarification (3 l
A)] systers per.etrating containment have been evaluated and identified as either essential or nonessentia].
Tacle 6.2-17 provides the results of this evaluation for each line, and Table 6.2-27 provides the basis for the selection of cssential/nenessential syste.s.
Position (3), Clarification (2 l
Systems deterrined to be nonessential are provided with diverse, automatic isolation signals, except as descrioed in the response to Position (1).
Manual valves are seales closed as discussed in l
Section 6.2.4.3.
I l
Positicn (4), Clarifications (4*,
5' l
The control systers for autcratic iso:stion valves are such that I
resetting the isolation signal will net result in the automatic reopening of these valves.
Ganged recper.ing cf cc~r.tainment isolation valves is perforned cnly where the operatien of 4
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'to protect the core in case of a pessible break in the Re-actor Water C3eanup Systes, to protect the ton exchange resin fron damage due to high cenperature, and to prevent the-renoval of boron by the ion exchange resin.
Clost.E The Rb'CU systen is described in FSAR Section tires of the EVCU isolation valves have been chesen in order
[
to prevent the reactor vessel water level fro-falling te-low the top of attive fuel if a break vere to c: car in an of the RL'CC lines. Diverse isolation signals are supplied t o iselate the P.k'CC in the unli',ely event of such a lir.e b r e a'<. The syste :. is intentionally left in service whe-ever the abcve isolatten signals are net activated in order to Provide continueus purification of a portion cf the recircu-l ap.
1ation flow.
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detect possible
__. __~_.f{! The applicant must either demonstrate th j leakage from the main feedwater lines and RCIC and RWCU supp!y lines that
' connect to the main feedwater lines are provided or commit to administrative
' ' procedures to eJose the remote-manually actuated containment iso.!ation valves on these lines short)y (e.g., within 20 minutes) fo!!owing.a LOCA or sooner if-Information Indicates a degraded core condition exists. (Confirmatory item) 1 l
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, containment isolation barriers, are~ maintained.
All power-operated isolation valves have position indicators in the control room.
Discussion of instrumentation and controls for the l
isolation valves is included in Chapter 7.
6.2.4.3.1 Evaluation Against General Design Criteria 6.2.4.3.1.1 Evaluation Agains't General Design Criterion 54 All piping systems penetrating containment, other than instrument lines, are designed in accordance with Criterion 54.
6.2.4.3.1.2 Evaluation Against Criterion 55 Criterion 55 requires that lines which penetrate the primary containment and form a part of the RCPB must have two isolation valves; one inside the containment and one outside, unless it can be demonstrated that the containment isolation provisions for a specific class of lines are acceptable on some other basis.
The RCPB, as defined in 10 CFR Part 50, Section 50.2 (v),
consists of the reactor pressure vessel, pressure retaining appurtenances attached to the vessel, and valves and pipes that extend from the reactor pressure vessel up to and including the outermost isolation valve.
6.2.4.3.1.2.1 Influent Lines Influent lines that penetrate the primary containment and connect directly to the RCPB are equipped with at least two isolation valves, one inside the drywell, and the other as close to the external side of the containment as practicable.
6.2.4.3.1.2.1.1 Feedwater Line The feedwater line is part of the RCPB as it penetrates the drywell to connect with the reactor pressure vessel.
It has three isolation valves.
The isolation valve inside the drywell is a check valve located as close as practicab1'e to,the containment wall.
Outside the containment is an air-assisted check valve located'as close as practicable to the containment wall, and farther away from the containment is a motor-assisted check valve on the feedwater line.
Additional isolation valves are located on lines connecting to the feedwater line outside containment.
Should a break occur in the feedwater line, the outboard check valves prevent significant loss of reactor coolant inventory and offer immediate isolation.
(It is impractical to restrain the inboard check valve to withstand pipe whip resulting from a downstream feedwater line break; therefore it cannot be assumed to isolate for this case.)
During a postulated LOCA, it is desirable to maintain reactor coolant makeup from all sources of supply.
For this reason, the feedwater lines are not Rev. 16, 01/83 6.2-48
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automatically isolate upon signals from the protection system.
'+Ehe outermost valve,is capable of being remotely closed from the control room to provide long-term leakage protection u^kS5 iNo s
.[udakr Imes arc. providhg readse caelant moeup.
The air-assisted check valve is provided with a special actuator that performs the following functions:
The. actuator is capable of partially moving the valve a.
disc into the flow stream during normal plant operation in order to ensure that the valve is not bound in the open position.
The actuator is not capable of fully closing the valve against flow, however, and there is no significant disruption of feedwater flow.
b.
T'he actuator is capable of applying a seating force to the valve at low differential pressures and abnormal conditions.
This improves the leaktightness of the valves.
The actuator is not utilized during leak testing.
6.2.4.3.1.2.1.2 HPCI Line The HPCI line connects to CS loop B that penetrates the drywell to inject directly into the RPV.
Isolation is provided by two
(-
valves in the CS line, an air testable check valve inside the containment, and an air assisted check valve outside the containment, with positions of both indicated in the main control The core spray loop B line is also provided with a room.
normally closed motor-operated globe valve which bypasses the inboard isolation valve for equalization during testing.
6.2.4.3.1.2.1.3 LPCI and CS Loop A The LPCI lines and CS loop A line are provided with remote manually controlled gate valves outside and air testable check valves inside containment.
Both types of valves are normally l
closed with the gate valves receiving an automatic signal to open i
at the appropriate time.
The check valves are located as close as practicable to the RPV.
The normally closed chepk valves protect against containment presturization if there is a pipe rupture between the check valve and containment wall.
The core spray loop A line and the LPCI lines are also each provided with a normally closed motor-operated globe valve which bypasses the inboard isolation valve for testing purposes.
Rev. 6 6.2-49
.~
6.2.4.3.1.2.1.4 RHR Head Spray Line The RHR head spray line penetrates the drywell and discharges directly into the RPV.
Isolation for this line is provided by a remote manually controlled gate valve inside containment and a remote manually controlled globe valve outside containment.
Both valves are normally closed and receive an automatic isolation l
signal if there is an accident.
l l
6.2.4.3.1.2.1.5 Recirculation Pump Seal Purge Line l
The recirculation pump seal purge line extends from the CRD supply line outside primary containment, penetrates primary containment through an excess flow check valve outside and a check valve inside containment, and connects to the recirculation pump seal housing.
The 1-inch recirculation pump seal purge line is Quality Group Classification A from the pump up to and including the excess flow check valve outside containment.
Should this line be postulated to fail and either one of the check valves is assumed to fail open, the flow rate through a' broken line outside containment is calculated to be substantially less than that permitted for a broken instrument line.
l Therefore, the two check valves in series provide sufficient isolation capability for the postulated failure of this line, t
6.2.4.3.1.2.1.6 Standby Liquid Control System Lines The SLC system line penetrates the drywell and connects to the RPV.
In addition to a simple check valve inside the drywell, a motor-operated globe stop check valve is located outside the drywell.
Since the SLC line is a normally closed, nonflowing line, rupture of this line is of extremely remote probability.
An explosive-actuated valve provides an absolute seal for long-term leakage control, provided the SLC system has not been utilized.
6.2.4.3.1.2.1.7 RWCU System The RWCU pumps, heat exchangers, and filter /de ineralizers are located outside the drywell.
The return line from,Sthe filter /demineralizers branches into three separate lines outside the drywell.
One line connects to the RCIC line that connects to l
the B feedwater line penetrating the drywell and injecting directly into the RPV.
The second branch connects directly to the A feedwater line that penetrates the drywell and injects directly into the RPV.
Isolation of both these lines is provided by the feedwater system check valves inside and outside the containment and an air-operated check valve in the connecting RWCU return line.
Rev. 16, 01/83 6.2-50
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Following a LOCA, it is desirable to maintain reactor coolant makeup.
For this reason, the above isolation valves are not provided with automatic isolation signals. PrA motor-operated globe valve is provided for long-term leakage control.
Should a break occur in the RWCU return line, the check valves prevent significant loss of inventory and offer immediate isolation, while the motor-operated globe valve provides long-term leakage control.
The third line penetrates the drywell and then connects to the A feedwater line that injects directly into the reactor pressure vessel.
This line is only used during outages.
Isolation is provided by one locked-closed globe valve inside containment and I
one locked-closed globe valve outside containment.
6.2.4.3.1.2.1.8 RCIC Line The RCIC line connects to the B feedwater line outside l
containment that penetrates the drywell to inject directly into the RPV.
The feedwater line has a check valve both inside and outside the drywell.
In addition to these two isolation valves, a motor-operated gate valve is located in the RCIC line that is normally closed and receives an automatic signal to open.
Th44r valve car be remete reneelly ircleted er derred recerrary by th-s & Qe % manual close oh
(.
ytant p&'dM3 FCAtI* e00lAat me heup, cycr ter Gllnbrq a.LOCA%h helAkon & LAnle% b'M b frevi 6.2.4.3.1.2.1.9 RHR Shutdown Cooling Return The RHR shutdown cooling return line penetrates primary containment and discharges into a recirculation pump discharge line that injects directly into the RPV.
Isolation is provided by an automatically actuated motor-operated globe valve outside containment and an air testable check valve inside containment.
~
6.2.4.3.1.2.2 Effluent Lines Effluent lines that form part of the RCPB and penetrate containment are equipped with at least two isolation valves; one inside the drywell and the other outside, located as close to the containment as practicable or justified on an alte(nate basis.
6.2.4.3.1.2.2.1 Main Steam, RCIC and HPCI Steam Lines, and RHR l
Shutdown Cooling Supply Line The main steam lines extend from the RPV to the main turbine and condenser system, and penetrate the primary containment.
For these lines, isolation is provided by automatically actuated globe valves, one inside the containment and one just outside the l
containment.
The main steam line isolation valves are l
spring-loaded, pneumatic, piston-operated globe valves designed
('
to fail closed on loss of pneumatic pressure or loss of power to the solenoid-operated pilot valves.
Each valve has two 6.2-51 Rev. 16, 01/83
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i The two H /02 sampling lines connected to the 24-inch and !&-inch drywe!! and 2
.; suppression po61 exhaust lines contain only a single containment isolation valve.
- . Either a second containment isolation valve is required, or the applicant rnust
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i I .i ~ . 1 o !! Asm G A secored containment isolatkm barrier, such as a esosed systern inside or outside _______ ' containment, must be provided for the dryweH presure, suppression pool level, suppression chamber pressure, and drywell sump level Instrument lines in addithm to the existing remote-manually actuated containment isolation valve located l outside_ containment. Also, Justification is required for not requiring the automatic
- asolation of the &vwell sump level instrument lines since this instrumentation is not
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_. g.__ _ ~ LGS FSAR 6.2.4.3.1.5 Evaluation Against Regulatory Guide 1.11 Instrument lines that penetrate the containment from the RCPB conform to Regulatory Guide 1.11 in that they are equipped with a restricting orifice located inside the drywell and an excess flow check valve located outside and as close as practicable to the containment. Should an instrument line that forms part of the reactor pressure boundary develop a leak outside the containment, a flow rate that results in a differential pressure across the valve of 3 to 10 psi causes the excess flow check valve to close automatically. Should an excess flow check valve fail to close when required, the main flow path through the valve has a resistance to flow at least equivalent to a sharp-edged orifice of 0.375 inch diameter. Valve position indication is provided in the reactor enclosure. Those instrument lines that do not ' connect to the RCPB conform to Regulatory Guide 1.11 in that they are either equipped with an excess flow check valve or an isolation valve capable of remote operation from the control. room, and are sized or orificed to meet the criteria outlined in Regulatory Guide 1.11. he status of the isolation valves capable of remote operatio rom the control room is indicated in gg the control room. C The TIP system lines as shown in Figure 9.3-2 and described below are considered instrument lines because (a) they function as instrument lines or support the operation of instrument lines, and (b) they are small diameter lines. TIP system isolation valves are provided on each guide tube immediately outside the containment. Dual barrier protection is provided by a solenoid operated ball valve and an explosive actuated cable shearing valve. The ball valve is closed except when a TIP is inserted. These valves prevent loss of reactor coolant in the event that an incore guide tube ruptures inside the reactor vessel and prevents the escape of primary containment atmosphere. The guide tube ball valve solenoid is normally de-energized and the valve is in the closed position. When the TIPJstarts forward, the valve solenoid is energized and the valve is held open against its spring. As the valve opens, it actuates a set of contacts which provide position indication at'the TIP control panel and a permissive signal for TIP motion. Upon receipt of a containment isolation signal (reactor low water level or high drywell pressure), the TIP drive mechanism is signalled to retract the TIP. As the TIP is withdrawn into its shield chamber outside containment, a position switch signals the ball valve to close. () The shear valve is provided as a backup in the event that a TIP cannot be retracted or a ball valve sticks open when containment 6.2-59 Rev. 15, 12/82
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l MuLM Because the sptems inside containment to which the recirculation pump cooling water supply and return lines and the drywell chilled water supply and return lines l' connect are not dosed systems G.e.,not Safety Class 2 and/or not seismic ~~ CategoryI and not protected against missiles and pipe whip) the containment he. revised to meet ZGDC 36 1seestian : design af these penetrations 'inust reqs.......ts. fThe W% :=sponse in NRC.6% 410.40.has not ry.ssived ~ this openitem. IDpenitem) wa 7w \\ A - cAJA J A .A . s. -k KM2 _A4 qA: \\ - -- a rk sr m A,xasu, - 2LEphA adud% _- a o u._ __ _ ___ _ _ W As,u.z,wa.w.u a.u.z. r.sIe_s 1g, ci_w,c.eaf 4.2Lerp.ra Y. we s. S l M _, % 2.-1 7.. Q)u.eshs 460 <26, s__%90.yo -w+-ow-- m _m 44.- -.us. rug---e,-emem-mes-- m.m-- m.m.-h<mm,-*um -em - - = = --- - - - ei-+--W
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=. -. =$ d en \\. S hM LGS FSAR (~ SA'hCn asWdy kd e rr multiple valves is required for system o ation. Sample inlet and return valve controls for the dryw radiation monitors and combustible gas analyzers are ganged s described in Sections 6.2.4.3.1.3.2.8 and 6.2.4.3.1.3.2.1. E'rywell chilled water valve controls are ganged as described in Sectiont 6.2.4.3.1.tEFJ.2,//, j Position (5), Clarification (6) l The setpoint for the drywell high pressure isolation signal is set at the minimum compatible with normal operation. Section 7.3.1.1.2.4.6 describes the selection of the drywell high pressure setpoint. Position (6), Clarification (7) l Containment purge valves comply with Branch Technical Position CSB 6-4 as discussed below. Two purge isolation valves have closure times greater than 5 seconds: 2"-HV-105 and 2"-HV-111 have closure times of 30 seconds. An analysis of the radiological consequences of a LOCA that occurs during purging was performed to justify the line size and the valve closure time used in the purge system. Using the assumptions of BTP CSB 6-4, the resulting doses were a small fraction of the 10CFR100 limits. For local leak rate tests, the' leakage rate of the purge (- penetrations and valves subject to Type B and C tests will be isolation valves, combined with the leakage rate for all other less than 0.60 La, in accordance with Appendix J to 10CFR50. Position (7) l The containment purge isolation valves isolate on receipt of any one of the following signals: a. high drywell pressure l b. reactor low water level l c. reactor enclosure high radiation l d. refueling floor high radiation l An analysis has been performed to demonstrate that the offsite doses that might result if a LOCA were to occur during purging operations would be less than both 10CFR100 and EPA Protection Action Guide limits. This analysis used the assumptions of NUREG 0800 Section 6.2.4 and Branch Technical Position CSB 6-4 and assumes a pre-existing spike that results in coolant activity levels in excess of Technical Specification limits. The analysis methodology was in accordance with the letter from T.J. Dente (, (BWR Owners Group) to D.G. Eisenhut (NRC) " Supplement to BWR Owners Group Evaluation of NUREG 0737 Item II.E.4.'2(7)", dated t June 14, 1982. 1.13-39 Rev. 16, 01/83
LGS FSAR 1 (2) Field audits are performed by representatives of the originating design group to ensure that the final installation of such items is in accordance with documents that formed the basis for the seismic analysis of the items. (3) Such items are not included in the "0" List. 3.2.2 SYSTEM OUALITY GROUP CLASSIFICATIONS General Design Criterion 1 of 10 CFR Part 50, Appendix A, requires that structures, systems, and components important to safety be designed, fabricated, erected, and tested to quality standards commensurate with their importance to safety. Components of the reactor coolant pressure boundary meet the N requirements for Class 1 components of the American Society of l Mechanical Engineers (ASME) B&PV Code, Section III, or equivalent quality standards, as required by 10 CFR Part 50.55.a. Regulatory Guide 1.26, Rev. 3, describes a quality classification system that may be used to determine applicable standards for other components in nuclear power plants. Quality group classifications are assigned to systems and components in accordance with the reliance placed on these systems to: a. Prevent, or mitigate the consequences of, accidents and malfunctions originating within the RCPB b. Permit shutdown of the reactor, and maintain it in the safe shutdown condition c. Contain radioactive material A tabulation of quality group classification for each component so defined is shown in Table 3.2-1 under the heading, " Quality Group Classification." The applicable codes and standards of [ each quality grougtare given in Table 3.2-2. The locations of these components, and the quality group classification of the piping, valves, and interfaces between components of different classifications, are indicated on the system piping and instrumentation diagrams in the pertinent section of the FSAR. A cross reference of system to FSAR figure number is provided in Section 1.7. System quality group classifications, and design and fabrication requirements as indicated in Table 3.2-1, meet the guidelines of Regulatory Guide 1.26, except as noted below. The Limerick design is based on quality group commitments made before Regulatory Guide 1.26 was issued, and in some cases alternate approaches to the guide have been used, as follows: 95 k M n# N dy fy 4I &iki?ff, 3.2-4
l LGS FSAR ( to full quality assurance requirements (0-listed), and was designed to seismic Category I criteria. e. Instrument tubing downstream of the containment isolation valve of instrument lines connected to the reactor coolant pressure boundary is Quality Group D for instruments that are " passive" (i.e., do not actuate safety systems), rather than Quality Group B or C as discussed in Paragraphs 1.e and 2.c of the guide. This is based on considerations given in Regulatory . Guide _._1.11 f or. instrument _1ines - penetrating containment- ------- ]" and having_two restriction devices, w / p.__-. -.3.2.3 -QUALITY ASSURANCE-Structures, systems, and components whose safety functions require conformance to the applicable quality assurance requirements of 10 CFR Part 50,' Appendix B, are summarized in Table 3.2-1 under the heading, "Q-List." Quality assurance during construction is discussed in PSAR Appendix D. The quality l assurance program during the operational phase is described in Chapter 17. 1 / 3.2-7 Rev. 19, 04/83 _m
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LGS FSAD TABLE 3.2-1 (Cont'd) (Page.1; CUALITY SOURCE GROUP PRINCIPAL OF I/)CA-CLAEEI-CCDES AND SEISMIC Cr-FSAR SUPPLY TICN FICATION STANDAPDS CATEGORY EIST IIIIEtZCCMPOUfdr[ ( 40 ] JICHQF f 11* .I21* _LJ_l*_ f4J! f 51* f 61* C9titM f. Ducttsork and registert, P R AISI/AWS I Y [231 C. PriMIy Containment '~ 1. Drywell cooling System 9.2.10, 9.4.5 a. Piping and valves P 7,R D B31.1 II, IIA N . _ b. Motors, fan P-C IEEE-334/ I Y NEMA-F4-1 c. Fans P C AMCA I Y d. Coils, cooling P C ARI IIA N e. Ductwork P C AISI/ANS I Y [ 23 ) ~ AMCA I Y 1. Dampers P C a. Chilled water equipment P R D MF STD II N h. Chilled water isolation valves P R /D III-2 I Y at primary containment
- i. Piping associated with P
C
- D B31.1 I
Y ( 4 8, 23 isolation valves at primary containment penetration 2. Purge System a. Piping and valves P 2 B III-2 I Y ( 481 b. Piping and valves, beyond P R C B31.1 IIA E outeracst containment isolation valves (smaller than 18-inch nominal diameter) 3. Hydrogen recombiner a. Piping and valves P R B III-2 I Y (481 b. Reaction chamber P R B III-2 I Y c. Blower P R R III-2 I Y 4. Vacuum relief system a. Valves P C N III-2 ) Y. D. Edd!fante and offaas rneiosure 9.4.3 + 1. Fans P Rn. AMCAf' II N 2. Coils, cooling P FW ARI II N KF SI3 II N 3. Heating coil, steam P RW 4. Ductwork P RW,T, SMACNA II N CS l Rev. i9c /
LGO FSAR (Page,20, TABLE 3.2-1 (Cont'd) i OUALITY SOURCE GROUP PRINCIPAL OF LOCA-CIASSI-CCDES AMD SEISMIC C-FSAR SUPPLY TION FICATION SIANDARDS CATEGORY LIST SYSTEM /CQMPONENT [ 40 ] EEC11CN f 11* f 21* f 31* f 41* f51* I61* COMMEartS XI &HILIARY SYSTEHj A. Eg[gguard PiciDa fjll System 6.3 IDSML lDg f eedwater fill Systgg) d 1. Piping and valves, from an3 including P R A III-1 I Y [48] isolation valves, to feedwater lines 2. Piping and valves, other P R B III-2 I Y [48] -.3._ Pumps P R-B .III-2 I Y i B. EMEPES22 on Pool Cleanur Systen Fig. 6.3-9 1. Piping and valves, to second P R B III-2 I Y [48] isolation valve 2 Piping and valves, after second P R D B31.1 IIA N isolation valve ~ 3. Pumps P R D MF SID IIA N C. pagineralized Water unkeun System 9.2.5 0 1. Tanks P W API-650 II N B31.1 II N 2. Piping and valves P ALL B31.1/ II N 3. Pumps P W HYD.I D. Qgrygjl Chilled Water Swatam 9.2.10 1. Chillers P T D VIII-1 II N ARI II, IIA N I 2. Cooling coils P T 3. Piping and valves, other P T,R D B31.1 II, IIA N 4. Valves, isolation to primary containment P R B III-2 I Y 5. Pumps P, T D HYD.1/ II N B31.1 fd 6. Piping associated with isolation valves P C f" B B31.1 I Y I48 2 at primary containment penetration E. M 1K21 Structure chilled Water System 9.2.10 'l 1. Piping P CS D B31.1 1 Y, f48] 2. Valves P CS D B31.1 I Y 3. Pumps P CS C III-3 I Y IEEE-323, I Y 4. Motors, pump P CS 344 i 5. Chillers (except condensers) P CS D V 6. Chiller condensers P CS C III-3 I r Rev. 19, C' j l
'^ ~- LGS FSAR (, TABLE 3.2-1 (Cont'd) (Page 35 of 38) [21U:;i xI Tk bA8i8 !8f Cbd[AAl1En o8 Nm-AIME fecdlm.G~ eg w)m a t ,. M 9 Smp B is y./A/ ih sub s.2.2,y. p, [22] Diesel fuel oil storage tanks and transfer pumps were designed to ASME Section III, Class 3 but were not stamped. [23]The structural design of seism'c Category I and IIA HVAC i ducts was verified by testing duct specimens as permitted by the AISI Code, to substantiate the duct width to duct sheet thickness ratio (w/t) and duct height to duct sheet thickness ratio (h/t) of up to 1500. Seismic Category II ducts were designed and constructed in accordance with SMACNA. [24}NRC Regulatory Guide 1.52, July 1976, suggests various industry standards and codes for this equipment. These references were used for system design, with exceptions as noted in Section 6.5. [25] Dampers with electro-hydraulic operators were designed to (, IEEE-323. Fire dampers are labeled by Underwriters' Laboratories. [26] Portions of ducts and dampers in the reactor enclosure and refueling floor HVAC system are seismic Category II, non 0-listed, and the remainder are seismic Category I, 0-listed. [27] Deleted [28)The main steam system (MSS) from its outer isolation valve up to, but not including, the turbine stop valve and bypass valve chest, and all branch lines 2-1/2 inches in diameter and larger up to, and including, the first valve (including their restraints), will be designed by the use of an appropriate dynamic seismic-system analysis to withstand the Operating Basis Earthquake (OBE) and Safe Shutdown Earthquake (SSE) design loads in combination with other appropriate loads, within the limits specified for Class 2 pipe in the ASME, Section III Code. The mathematical model for the dynamic seismic analyses of the MSS and branch line piping includes the turbine stop valves and the piping from the stop valves to the turbine casing. The dynamic input loads for ( design of the MSS are derived from a time history model analysis (or an equivalent method) of the reactor and Rev. 17, 02/83
....y._..-....._..... i LGS FSAR The secondary containment design data are in Table 6.2-14. 6.2.3.2.2 Secondary Containment Isolation System Isolation dampers and the plant protection signals that activate the secondary containment isolation system are described in Section 9.4.2.1.3. 6.2.3.2.3 Containment Bypass Leakage Upon receipt of a reactor enclosure isolation signal, the reactor enclosure recirculation system (RERS) and the SGTS are automatically activated and begin to process all air flow streams from the reactor enclosure ventilation system. Therefore, if a LOCA occurs, radioactivity that oxfiltrates the steel-lined primary containment or piping systems containing radioactive fluids is collected and passed through the RERS and SGTS as described in Section 6.5. The potential paths by which leakage from the primary containment can bypass the areas serviced by the SGTS have been evaluated. Table 6.2-15 identifies all primary containment penetrations, the termination region of all lines penetrating primary containment, and the bypass leakage barriers in each line. It has been t' determined that no potential bypass leakage paths exist for the (. entire spectrum of LOCAs except for a feedwater line break inside containment. A water seal cannot be maintained in the broken feedwater line by the feedwater fill system (Section 6.2.3.2.3.2) for the case of a feedwater line break inside containment. For this case, containment leakage may travel past the broken feedwater line's containment isolation valves into the portion of the feedwater line located in the turbine enclosure. However, a water seal in this portion of the feedwater line would realistically be expected to be maintained by water from the condensate storage tank. Therefore, no bypass leakage is postulated to reach the environment. When designating the termination region, if either the system line that penetrates primary containment or any branch lines connecting to it penetrate the secondary containment, the termination region is listed in Table 6.2-15 as outside secondary l l containment (OSC). The types of bypass leakage barriers employed by these lines are: 1. Redundant primary containment isolation valves 2. Closed __i__l. CJ.:;;, i piping system insi3e containment 3. A water seal maintained for 30 days following a LOCA (. 6.2-43 Rev. 15, 12/82
.___.J__..: LGS FSAR 4. The line beyond the outboard primary containment isolation valve is vented to secondary containment by use of a vent line located upstream of the two block valves. 5. A leakage collection system is provided. 6. The line contains a temporary spool piece that is removed during normal operation and replaced by blind flanges so that any leakage through the flange is into secondary containment. 3 Type 1 leakage barriers are considered to imit but not eliminate bypass leakage. Leakage barriers of types through 6 are considered to effectively eliminate any bypass leakage. Leakage from those lines terminating in the reactor enclosure is collected during the LOCA because the reactor enclosure is restored to and maintained at subatmospheric pressure and all exhaust is processed by the RERS and SGTS during these modes (Section 6.5). Therefore, lines terminating within the reactor enclosure are net considered potential bypass leakage paths. Lines penetrating primary containment are isolated following a LOCA as described in Section 6.2.4. All containment isolation valves and penetrations are designed to seismic Category I requirements. The primary containment and penetration leakage is monitored during periodic tests as discussed in Section 6.2.6. Those penetrations for which credit is taken for water seals as a means of eliminating bypass leakage (Table 6.2-15) are preoperationally leak-tested with water and Technical Specification leakage rates are given as water leak rates. 6.2.3.2.3.1 Water Seals In each case where water seals are used to eliminate the I potential of secondary containment bypass leakage, a 30-day water seal is assured because either a_ loop seal is present or the water for the seal is provided from a large reservoir. The water seals for all of these lines will be maintained at a pressure j greater than the peak containment accident pressure. Each of the water seals listed in Table 6.2-15 is discussed below (some l penetrations may be listed more than once due to the presence of multiple types of water seals), a. Penetrations 9A & B and 44. The feedwater fill system (Section 6.2.3.2.3.2) is used to maintain a water seal in the lines downstream of these penetrations. Rev. 15, 12/82 6.2-44
on 4 LGS FSAR (' b. Penetrations 204A & B, 207A & B, 208B, 210, 212, 215, l 216, 217, 226A & B, 235, 236, 238, 239 and 240. The lines associated with these penetrations all penetrate the wetwell above the suppression pool water level and terminate at least 4 feet below the minimum suppression pool water level. A 30-day water seal is therefore assured on the submerged portion of line. l c. Penetrations 13A & B, 16A & B, 17, 39A & B, 45A-D, 205A l & B, and 225. Piping connected to these penetrations is normally full of water and will be kept full after a LOCA due to operation of the ECCS and/or safeguard piping fill system. The suppression pool is the water source for the ECCS and fill system, and therefore a 30-i l day water supply is assured. l d. Penetrations 203A-D, 206A-D, 209, 214 and 237. The lines associated with these penetrations all penetrate the wetwell at least 11 feet below the minimum water level of the suppression pool, and therefore a 30 day water seal is assured. e. Penetrations 231A & B'. The line to the containment isolation valves from the drywell floor drain sump is ( maintained full of water by an elevation difference i \\ between the sump and the valves. The line to the containment isolation valves from the drywell equipment drain tank is maintained full of water by an elevation difference between the tank and the valves. f. Penetrations 10, 11, 12, 44, 228D and 241. Li'nes associated with these penetrations that pass through the secondary containment boundary and take credit for water seals are provided with loop seals inside secondary containment, which eliminates the possibility of bypass leakage. g. Penetration 14. The minimum piping height inside primary containment of the RWCU supply line that branches off the recirculation loop is at El 267 ft. The primary containment penetration is at El. 297 ft and l the RPV penetration is at El. 280 ft. This elevation difference ensures that a water seal is maintained in the line from the RPV to the containment isolation valves. The RWCU supply branch line that connects to the bottom cf the vessel is normally full of water, and i the water will be maintained in this line because it connects directly to, and below, the vessel. h. Penetrations 37A-D and 28A-D. The CRD insert and ( withdraw lines are normally full of water. A water seal will be maintained in these lines after a LOCA due to 6.2-44a Rev. 15, 12/82
LGS FSAR ) the elevation difference between the containment penetrations (El. 265 ft) and the connections to the control rod drives (El. 215 ft). 6.2.3.2.3.2 Feedwater Fill System The feedwater fill system prevents the release of fission products through the feedwater containment isolation valves after a LOCA by providing a water seal downstream of the valves. 6.2.3.2.3.2.1 Safety Design Bases The feedwater fill system is designed with sufficient capacity and capability to prevent leakage through the feedwater lines under the conditions associated with the entire spectrum of LOCAs except for a feedwater line break inside containment. The feedwater fill system conforms to seismic Category I requirements. Quality group classifications are shown in Table 3.2-1, Item XI.A. The system meets the intent of Regulatory Guide 1.96, where applicable. The feedwater fill system is capable of performing its safety function considering the effects resulting from a LOCA, including missiles that may result from equipment failures, dynamic effects associated with pipe whip and jet forces, and normal operating and accident-caused local environmental conditions consistent with the design basis event. Furthermore, any portion of the feedwater fill system that is quality Group A and is located outside the primary containment structure is protected from missiles, pipe whip, and jet force effects originating outside the containment so that containment integrity is maintained. The feedwater fill system is capable of performing its safety function following a LOCA and an assumed single active failure. The feedwater fill system is designed so that effects resulting from a single active component failure do not affect the integrity or operability of the-feedwater lines or the feedwater containment isolation valves. The feedwater fill system is capable of performing its safety function following a loss of all offsite power coincident with a postulated design basis LOCA. The feedwater fill system is designed to prevent leakage from the feedwater lines consistent with maintaining containment integrity for up to 30 days. The feedwater fill system is manually actuated and is not required to be actuated sooner than 30 minutes after a LOCA. Rev. 15, 12/82 6.2-44b
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i LGS FSAR } rupture of piping d. Environmental design Section 3.11 Debris transported to the suppression pool by the emergency core cooling water is prevented from entering the ECCS suction lines by suction strainers. The suction strainers are described in Section 6.2.2. Ensurance of the operability of valves and valve operators in the containment atmosphere under normal plant operating conditions and postulated accident conditions is discup& yk AW8 9/dedtsM sed Jn Section).9.3. dante /d Provisions for detecting leakage from systemp'provided with remote manual isolation valves are discussed ',n Section 5.2.5. The design provisions for testing the operability of the isolation valves and the leakage rate of the containment isolation barriers are discussed in Section 6.2.6. A leakage control system is provided for the main steam isolation valves, and is discussed in Section 6.7. A seismic Category I i fill system provides a water seal for the feedwater lines, as discussed in Section 6.2.3.2.3. Containment isolation valve closure times are selected to ensure rapid isolation of the containment following postulated accidents. The isolation valves in lines that provide an open path from the containment to the environs have closure times that minimize the release of containment atmosphere to the environs to below 10CFR100 guideline values, mitigate the offsite radiological consequences, and ensure that ECCS effectiveness is i not degraded. These valve closure times are identified with a l double asterisk in Table 6.2-17. The isolation valves for lines in which high-energy line breaks can occur have closure times that minimize the resultant pressure and temperature transients as well as the radiological consequences. These valve closure times are identified with a single asterisk in Table 6.2-17. All of the isolation valve closure times listed in Table 6.2-17 are the actual closure times that the isolation valves were purchased with, which in all cases are equal to or lower than the closure times necessary to meet the aforestated design requirements. Those closure times which are required to be met to satisfy isolation valve closure time design requirements are identified by a single or double asterisk in Table 6.2-17. The essential / nonessential classification of containment isolation valves, as listed in Table 6.2-17, was based on the following: those systems identified as essential are regarded as indispensable or are backup systems in the event of an accident; nonessential systems have been judged to not be required after an Rev. 16, 01/83 6.2-46 = _.
LGS FSAR In addition, the piping is considered an extension of the containment boundary and, as such, is designed to the same quality standards as the primary containment. The drywell radiation sampling isolation valves have ganged controls for reopening. Inboard sample and return isolation valves SV-190A and SV-190C are ganged on HS-190A. Outboard sample and return isolation valves SV-190B and SV-190D are ganged on HS-190B. 6.2.4.3.1.3.2.9 Primary Containment Instrument Gas The influent lines are provided with a normally-open power- ~ operated globe valve ~outside~the containment and a check valve inside the containment. Motor-operated valves are used on the influent lines that contain the ADS gas supply. These are essential lines that provide a long-term backup to the ADS accumu1~ators inslde conta~inment.~The valves on-~these~essentiar---~' ~ lines are remote manually operated and automatically isolate only - when flow out of containment through these lines would be possible (i.e., low differential pressure between the containment and the instrument gas line). The remaining influent lines are non-essential lines that use air-operated valves that are automatically closed on receipt of a containment isolation signal. The effluent lines are provided with normally-open air-operated globe valves inside and outside the containment that close automatically on receipt of a containment isolation signal. 3.1.3.3 Conclusion on Criterion 56 In order to* ensure protection against the consequences of accidents involving release of significant amounts of radioactive materials, pipes that penetrate the containment have been demonstrated to provide isolation capabilities on a case-by-case basis in accordance with Criterion 56. In addition to meeting isolation requirements, the pressure retaining components of these systems are designed to the same quality standards - containment. Evh{ul.vhk To Mt M % b p *wuwk uation Against Criterion 57 6.2.4.3.1.4 Criterion 57 describes criteria for closed system isolation valves. Influent and effluent lines of this group (re isolated *by automatic or remote manual isolation valves located as close as possible to the containment boundary. / 6.2-58a Rev. 19, 04/83
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LGS FSAR 6.2.4.3.1.4.1 CRD Lines ( The CRD system has multiple lines, the insert and withdraw lines, that penetrate primary containment. The classification of these lines is Quality Group B, and they are designed in accordance with ASME Section III, Class 2. The basis on which the CRD insert and withdraw lines are designed is commensurate with the safety importance of maintaining the pressure integrity of these lines. The CRD insert-and withdrawal lines are not provided with cutomatic c'ontainmerit~isolatidn~~ valves iK cirder tFmailmi~ze the ~ - ~ reliability of the scram function. A ball check valve located in the CRD flange housing automatically seals the insert line in the event.of_a line_ break.__The.inser.t__and. withdrawal lines terminate in hydraulic control units (HCUs) which contain multiple valves (manual, solenoid, air-operated, and check valves) to control CRD ~ movement'~ minimize ~ leakage,'and provide isolation.--All automatic-valves in the HCOs are normally closed and are open only during rod movement. Because the-scram valves in the HCU are normally open after a scram, the scram discharge volume is provided with redundant automatic vent and drain valves. [ h y 4.2 Reactor Enclosure Cooling Water and Drywell 1 11ed Water Supplies and Returns The influent and effluent are provided normally-open motor-operated gate valves that c te manually isolated from the control room. The drywel il ter isolation valves have controls for gan eopening. Loop fluent and effluent isolation valv -128 and HV-129 are gange S-128. Loop B influent an luent isolation valves HV-122 <.nd HV-e ganged on -122. N ~ s Rev. 19, 04/83 6.2-58b
LGS FSAR The containment isolation syster. conforms to Regulatory Guide 1.141 except as discussed below y y American National Standards Institute (ANSI) N271-1976 Sectton 3.5 iteria Fo Closed S tems Insi e Containmen. If a e osed system ins e conta ment is u d as one of he two containm t isola 'on barrier, it shall m t the er eria that fo ow... (2) e missi e, pipe wh , and jet f ce protec d from a LO or fro a missile, ipe whip, o jet force hat resul i a requi ement for ntainment is ation. (3) Me Safety C ss 2 design quirement. (7) eet seismi Category I sign requi ements. Limeri k Desian: C1 ed systems uch as react fnclosure cooling wat and l d well chille water are n / designed rictly in ccordance with items ( (3), and ( of Section 3.5 of ANSI N271. The (- design crit.fa used for ese systems are listed in Table 3.2-1. A w Section 3.6.4 Single Valve and Closed System Both Outside Containment... The single valve and piping between the containment and the valve shall be enclosed in a protective leaktight or controlled leakage housing to prevent leakage to the atmosphere. Limerick Desion: For systems that fall into this category except for the ECCS pump suction lines, the single valve outside primary containment is not enclosed in a protective leaktight or controlled leakage housing. Moderate energy lines that fall into this category do not connect to the reactor coolant pressure boundary and are not postulated to break concurrent with a LOCA. Therefore, neither reactor coolant nor post-LOCA containment atmosphere are released. However, any leakage is contained within the secondary containment and is diluted and filtered prior to release. The ECCS pump suction isolation valves are enclosed in pump rooms adjacent to the containment that have provisions for the environmental control of any fluid leakage. ( Section 3.6.5 Two Valves Outside Containment... 6.2-60c Rev. 15, 12/82
LGS FSAR ( Section 5.3.2 - Leakage Rate Testi,ng Provisions and Methods. Provisions shall be made for leakage rate testing of containment isolation valves. Limerick Desian: Individual leakage rate tests are performed for containment isolation valves as indicated in Table 6.2-25. Y ~ ~' s. Note: ~ ~ ~ ' ~ ~ ~ Regu'latory de Pa graphs ~ .4 and C.6 efer~ 271 - ~~' ~ Sections'4.4.8 ( sed sys m design and 4.)1 (piping tween isolation barr' rs) and ds the r uiremeprs of Secp'on 3.5/to thys'e sectio As di ussed abpfe,_ther4 is.part}di confp(mance 6.2.4.3.2 Failure Mode and Effects Analyses A single failure can be defined as a failure of some component in any safety system that results in a loss or degradation of the Active system's capability to perform its safety function. components are defined as components that must perform a mechanical motion during the course of accomplishing a system safety function. Appendix A to 10 CFR Part 50 requires that electrical systems be designed against passive single failures as well as active single failures. Section 3.1 describes the implementation of these requirements as well as General Design Criteria 17, 21, 35, 41, 44, 54, 55, and 56. In single failure analysis of electrical systems, no distinction is made between mechanically active or passive components; all fluid system components, such as valves, are considered electrically active whether or not mcchanical action is required. 6.2.4.4 Tests and Inspections The containment isolation system undergoes periodic testing I during reactor operation. The functional capabilities of power operated isolation valves are remotely tested manually from the main control room. By observing position indicators and changes in the affected system operation, the closing ability of a particular isolation valve is demonstrated. / k 6.2-6.1 Rev. 19, 04/83
D bt/\\ C LGS FSAR A discussion of testing and inspection pertaining to isolation i volves is provided in Section 6.2.1.6 and in Chapter 16. Tcble 6.2-17 lists all isolation valves. Instruments are be periodically tested and inspected. Test ond/or calibration points are supplied with each instrument. Excess flow check valves (EFCVs) are periodically tested by opening a test drain valve downstream of the EFCV and verifying proper operation. As these valves are outside the containment and accessible, periodic visual inspection is performed in - --cddition. to the operational check.. _ _ _ _ _ _.. _ _ _. _ _ _ Leak-rate testing for the containment isolation system is discussed in Section 6.2.6. 6.2.5 COMBUSTIBLE GAS CONTROL IN CONTAINMENT Following a postulated LOCA, hydrogen gas may be generated within the primary containment as a result of the following processes: Metal-water reaction involving the Zircaloy fuel a. cladding and the reactor coolant b. Radiolytic decomposition of water in the reactor vessel and the suppression pool (oxygen also evolves in this process) / Rev. 12, 10/82 6.2-62
LG3 FSAR TABLE 6.2-15 (Page 1 cf 5) EVALUATION OF POTENTIAL SECONDARY CONTAINMENT BYPASS LEARAGE PATES CONTAINMEFFF TERMINATION BYPASS IEARAGE PtFTENTIAL BYPASS PENETRATION SYST EM REGIONtt3 BARRIERStas phyN 1 Equipment access door ISC Double O-Ring No 2 Equipment access door and ISC Double 0-Ring No personnel lock 3A Main steam (MS) line D flow ISC No instrumentation 3B Inst gas supply OSC 1,4 No l 3C HPCI steam flow inst ISC No No 6 3D MS line A flow inst ISC 3D Instrument gas supply OSC 1,4 No j 4 Head access manhole ISC Double 0-Ring No 5 Spare 6 CRD removal hatch ISC Double O-Ring No 7A-D Primary steam OSC 1,5 No 8 Primary steam line drain OSC 1,4 No 9A5B Feedwater OSC 1,3 Nots 10 Steam to RCIC turbine OSC 1,3,6 No 11 Steam to HPCI turbine OSC 1,3,6 No 12 RHR shutdown cooling supply OSC 1,3 No 13ASB RHR shutdown return OSC 1,3 No 14 RWCU supply OSC 1,3 No 15 Spare 4 16ASB Core spray pump discharge OSC 1,3 No 17 RPV head spray OSC 1,3 No 18 Spare 19 Spare No 20A RPV level inst ISC No 20A LPCI AP inst ISC 20B LPCI AP inst ISC No No 20B RPV level inst ISC 21 Spare No 22 Drywell pressure inst ISC - = 23 Closed cooling water supply OSC 1 2,3,) No 34,23/ No 24 Closed cooling water return OSC 3 25 Drywell purge supply OSC No 26 Drywell purge exhaust ISC Mo 27A Instrument gas supply OSC 1,4 No l No 27B HPCI flow inst ISC No 28A Recire loop sample ISC ISC No 28A Drywell He/03 No 28B LPCI AP inst ISC No 28B Drywell air sample ISC No 29A RPV flange leakage inst ISC No 29B Core spray AP inst ISC No 30A MS line D flow tr.a.t ISC No 30B Drywell pressure inst ISC No 30B MS line C flow inst ISC Rev. 16, 01/93
IAG PSAR TABLE 6.2-15 (Cont'd) (Page 2 of 5) C3tCAINNENT TERMINATION E! PASS LEARAGE POTENTIAL BYPASS PENRTRATION SYSTEM REGIONt19 BARRIERStes pgTg No 31A88 Jet pump flow inst ISC No 32ASB Jet pump flow inst ISC 33A Pressure above core plate inst ISC 10 0 33A Pressure below core plate inst ISC No No 33B RCIC steam flow inst ISC 34A MS line C flow inst ISC No No 34B Recirc flow inst ISC 35A Inst gas to TIP indexing mechanism OSC 1,4 t00 35C-G TIP drives ISC No 36 Spare 37 A-D CRD insert OSC 1.3 No 3 8 A-D CRD withdraw OSC 1,3 No i 39A8B Drywell spray OSC 1,3 No 40A,BSC Jet pump flow inst ISC too 40D Pressure below core plate inst ISC IEo No 40E Drywell pressure inst ISC No 40F RCIC steam flow inst ISC 40F Inst gas suction OSC 1,4 No 40G ILRT data acquis system OSC 1,6 10 0 40R Instrument gas supply OSC 1,4 No l No 40R Recire pump cooler flow inst ISC No 41 LPCI SP inst ISC 41 RWCU flow inst ISC 10 0 too 42 Standby liquid control ISC No 43A Recire loop A AP inst ISC 43A Recirc pump seal pressure inst ISC No No 43B Main steam sample ISC 44 CRD/RWCU return OSC 1,3 No 45A-D LPCI OSC 1,3 No 46 Spare No 47 RWCU flow inst ISC No 48A RPV level inst ISC 10 0 - 48A Cor*2 spray AP inst ISC 10 0 4BB RPV level inst ISC No 49A8B MS line A6B flow inst ISC too SOA Drywell pressure inst ISC No SOA Pecirc flow inst ISC No i SOB Recire pump seal pressure inst ISC No SOB Pecirc pump cooler flow inst ISC too 51A Recirc line flow inst ISC l No 51B Jet pump flow inst ISC No i 52A MS line B flow inst ISC No 528 Recire line flow inst ISC t2.3) 82. NO 53 Drywell chilled water supply OSC 3 No 54 Drywell chilled water return OSC 55 Drywell chilled water supply OSC I, 2.5 No 56 Drywell chilled water return OSC 10 0 Rev. 16, 01/93
LG3 F3AR OC h TABLE 6.2-15 (Cont'd) (Page 5 cf 5) C3NTAINMENT TERMINATION BYPASS LEARAGE POTENTIAL STPASS PENFTRATION SYSTEM REGIONE83 BARRIERSta3 yATg t (*3 The termination regions are: ISC - Inside Secondary Containment OSC - Ountside Secondary Containment I (*3 The bypass leakage barriers are defined as follows (see section 6.2.3.3.3): 1. Redundant primary containment isolation valves 2. Closed piping system inside containment l 3. A water seal maintained for 30 days following a IDCA 4. He line beyond the outboard primary containmeytt isolation valve is vented to secondary containment by use of a vent line located between two block valves and the secondary containment. i 5. A leakage collection system is provided 6. The line contains a temparary spool pLece that is removed during normal operation and replaced by blind flanges so that any leakage through the flange is into secondary containment. l (83 The feedwater fill system will provide a water seal in the feedwater lines for all line breaks other than a feedwater line break inside containment. f I t Rev. 16. 01/93 ( l l I
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LCS FSAR TABLE 6.2-25 (Cont'd) (Page 3 of 139 INBOARD OUTBOARD ISOLATION BARR!ER ISOLATION PARRIER PENET. DRAW-TEST DESCRIPTIDW INSTRUMENT / No. SYSTEM INGE879 TYPE VALVE NUMBER VALVE NUstBER M3?R 21 Service air M-15 C 1140 1139 { 22 Instrumentation - drywell M-42 A MO-147C 11 I pressure l s%e-lob MD-10$ 23 Closed cooling water supply M-13 C 88e=880 1040 2.7 E 1 24 Closed cooling water return M-13 C --FV.0- 107 N-ill ^ asemees 1091 la,11 g 25 Drywell purge supply M-57 C A0-121 MO-109 3, 12 1 MO-163 Closed system ] AO-123 A0-131 MO-135 26 Drywell purge exhaust M-57 C SV-145 3, 1 MO-161 Closed system 5(MO-111 l MO-111 AO-117 only), l AO-114 MO-115 12 l 27A Indtrument gas supply C CK-1128 MO-151A ] 27B Instrumentation - HPCI flow M-55 A IPC-F024B 1 l 27B Instrumentation - HPCI flow M-55 A KFC-F024D 1 l / 28A Pecirc loop sampic M-43 C AO-F019 AO-F020 l 28A Drywell H,/0, sample M-57 C SV-134 SV-144 12 l 28A Drywell Ha/Oa sample M-57 C SV-132 SV-142 12 l 28B Drywell Ha/Os sample M-57 C SV-133 SV-143 12 SV-195 26B Spare A l 29A Instrumentation - RPV M-41 A KFC-F009 1 flange leakage 29B Instrumentation - CS AP M-52 A XFT-F018A 1 ] 30A Instrumentation - main M-41 A Xft-F071D 1 steam line D flow XFC-F072D 30B Instrumentation - drywell M-42 A MO-147A 11 pressum Rev. 16, 01/81
LGS FSAR TABLE 6.2-25 (Cont'd) (Page 6 of 13l INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENET. DRAW-TEST DESCRIPTION / I NSTRU. TENT / No. SYSTEM It3G( t ? S TYPE VALVE NUMBER VALVE NUMBER N3?E 46 Spa re l A 47 Insi.rumentation - RWCU flow M-44 A XFC-102D 1 l 48A Instrumentation - RPV level M-42 A XFC-F0658 1 XFC-F0478 48A Instrumentation - CS AP M-52 A XFC-F018B 1 l 48B Instrumentation - RTV level M-42 A XFC-F065A 1 l XFC-F047A l I 49A,9 Instrumentation - main M 41 A XFC-F071A,8 1 steam line A & B flow XFC-F072A,B 50A Instrumentation - drywell M-42 A MO-147B 11 pressure SOA Instrumentation - recirc M-43 A X K-F011A,B 1 flow XFC-F012A,B 50 B Instrumentation - recire M-43 A XFC-F004A 1' l pump seal pressure l SOB Instrumentation - recirc M-87 A Xft-156A l pump cooler flow XFC-157A l 51A Instrumentation - recire M-43 A XFC-r009A,B 1 l line flow XFC-F010A,B l 51B Instrumentation - jet M-42 A XFC-F059T 1 ) pump flow XFC-F051C XFC-F053C 52A Instrumentation - main M-41 A XFC-F070B 1 steam line B flow XFC-F073B XFC-F011C,D 1 l 52B Instrumentation - recire M-43 A line flow XFC-F012C,D l me-lg 6 m o-12o 4 53 Drywell chilled water supply M-87 C Esbe c. ' dameeg ne.stSA t a gt r. l 54 Drywell chilled water return M-87 C it44 WEE l l _mo - lE_t N bio-lZM Y l 55 Drywell chilled water supply M-87 C N -lZ.5 6 t I pev. 16, 01/83
LGS FSAR TABLE 6.2-25 (Cont'd) (Foge 7 of 13) INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENET. DRAW-TEST DESCRI PTiUNT INSTRUMENT / } _N o. SYSTEM IN3ttF9 TYPE VALVE NUMBER VALVE MUMBER WOTE mo-sLB mo-t 56 Drywell chilled water return M-87 C C:_ J ^- M mo u (3 ya %R 57 Instrumentation - RWCU flow M-44 A IFC-102C 1 58A Instrumentation - recirc M-43 A KFC-F040B 1 loop B AP 58B Spare A 59 A,B Spare A 60 Spare A 61 Recirc pump seal purge M-43 C CK-1004A, B XFC-103A,8 1, 19 62 He/0, sample return M-57 C SV-150 MO-116 12 SV-159 63 Instrumentation g-recirc M-43 A IFC-F0038 1 loop AP: recirc pump XFC-F004B Seal pressure XFC-F040D 64 Spare A 65A,B Instrumentation - RPV M-42 A XFC-F043B 1 pressure XFC-F049A 66A Instrumentation - RPV level M-42 A IFC-F045D 1 66A Instrumentation - LPCI M-51 A KFC-102D 1 8P XFC-103D 66B Instrumentation - RPV level M-42 A IFC-F045A 1 66B Instrumentation - LPCI M-51 A XFC-102A 1 AP XFC-103C 67A,B Instrumentation - RPV level; M-42 A XFC-F041 1 RPV pressure XFC-F043A XFC-F049B 100 Neutron monitoring system M-60 B Canister 8 A-D 101 Recire pump power M-60 B Canister 8 A-D Rev. 16, 01/83
I LGS FSAR (Page 12 ot IJ) TABLE 6.2-25 (Cont'd) 2. Penetration is sealed by a blind flange or door with double 0-ring ( seals. These seals are leakage rate tested by pressurizing between the l O-rings. l 3. Inboard butterfly valve installed such that tested in the reverse l direction is conservative. l Inboard gate valve tested in the reverse direction.V"" 4. l 5. Inboard globe valve installed such that testing in the reverse gjL, [ direction is conservative. cogAh l 6. The MSIVs are tersted by pressurizing between the valves. Testing of l the inboard valve in the reverse direction tends to unseat the valve l and is theref ore conservative. The valves are Type C tested at a test l pressure of 25 psig. ja l 7. Gate valve tested in the reverse direction. l 8. Electrical penetrations are tested by pressurizing between the sea l 9. The isolation provisions f or this penetration consist 'of two isolation l valves and a 4 -?-'d system outside containment. A single active l f ailure can be accommodated. The closed system is missile protected, l seismic Category I, quality group B, and is designed to the temperature l and pressure conditions that the system will encounter post-LOCA. I valves will remain water covered during Type A testing. System leakage l will be minimized in accordance with NUREG-0737, Item III.D.1.1. Any l leakage out of the closed system will be into the reactor enclosure, l 4 thus faciliting collection and treatment. l 10. The isolation provisions for this line consist of one isolation valve l outside containment and a closed system outside containment. A single l active failure can be accommodated. The closed system is missile l protected, seismic category I, quality group B and designed to the l temperature and pressure conditions that the system will encounter l post-LOCA. l System leakage will be mir.imized in accordance with NUREG-073F, Item l III.D.1.1. Any leakage out of the closed system will be into the l reactor enclosure, thus f acilitating collection and treatment. l 11. The valve does not receive an isolation signal but remains open to l measure containment conditions post-LOCA. Leaktightness of the l penetration is verified during the Type A test. l 12. All isolation barriers are located outside containment. l Rev. 16, 01/6J
LGS FSAR (Page 13 of 13) TABLE 6.7-25 (Cont'd) l, 13. Isolation provisions for the CPD insert and withdrawal lines cre described in section 6.2.4.3.1.4.1. The scram discharge volume vent and drain valves are Type C tested. l 14. The isolation provisions for this line consist of a suppression pool water seal, at least one isolation valve outside containment, and a closed system outside containment. The isolation valve is not exposed to the primary contaiment atmosphere because the line terminates below l the minimum water level of the suppressien pool. The closed system is j missile protected, seismic Category I, quality group B, and designed to l the temperature and pressure conditions that the system will encounter post-IDCA. valves will remain sater covered during Type A testing. System leakage is minimized in accordance with NUREG-0737, Item III.D.1.1. Any leakage out of the closed system will be into the j reactor enclosure, thus facilitating collection and treatment. I 15. The iso'lation barrier remains water filled post-LOCA and will be testes with water. 16. These lines penetrate the diaphragm slab and are not subject to Appendix J 1eakage rate testing. 0 17. Table 1.8-2 contains a cross-reference to figure numbers. l 18. Teedwater penetrations will remain water filled post-LOCA as described in Section 6.2.3.2.3. 19. Check valve used instead of flow orifice. l 20. Penetration is sealed by a flange with double 0-ring seals. These j seals are leakagt rate tested by preseurizing between the oThe TIP l drive tube is welded to the flange. l 21. Seismic Category I, Quality Group B instrue.ent line with an excess flow check valve. Because the instrument line is connected to a closed cooling water system inside containment, no flow orifice is provided. The line does not isolate during a LOCA and can leak only if the line l or instrument should rupture. ieaktightness of the line is verified during the integrated leak rate test (Type A test). ff k$ N A g fk ykh y & Ldh $ (J = J J, n & msw 4. Rev. 16, 01/83
RPV CONTAINMENT TC g MO pte P' V DETAIL
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(13) M, TC MO 4E eTL e -F7 k it O gg* RECIRC PUMP CW SUPPLY q DRYWELL CHILLED WATER SUPPLY d Er 3 / ( TC MLC MLC l DETAll X {' X ( (14) ALTERN ATE RWCU RETURN SV lI TC l MO AO e a i e 1 DETAIL {7J 8 (15) MO ( I MO ( i j 3 SUPPRESSION POOL PURGE EXHAUST ( MO-MOTOR OPER ATED AO-AIR OPERATED LIMERICK GENER ATING STATION TC-TEST CONNECTION UNITS 1 AND 2 MLC-MANUAL LOCKED CLOSED FINAL SAFETY ANALYSIS REPORT l Sp SOLENOID VALVE D) T iis vs.lv6 [6 N6d IOM CONTAINMENT ENETRATION cjsud on ymgo MP cu #VsTEn d) This vAul6 L'a ONL.V dst SHEET 5 OF 16 W/.Ato PiAmP c,V sysTfM. FIGURE 6.2 36 REV.11,10/82
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LGS FSAR g [c. Close'd Jy d pip tha re loc in the ent and etrat imar ontain t % priga6 contai ( twrfe one i' ation v eouts)d cont ment. The MSIV controls include pneumatic piping and an accumulator for the air-operated valves as the isolation motive power source in 4 addition to the springs. Pressure, temperature, and water level sensors are mounted on instrument racks or locally in either the reactor enclosure or the turbine enclosure. Valve position switches are mounted on motor-and air-operated valves. Switches are encased to protect them from environmental conditions. All signals transmitted to the control room are electrical (no pipe from the nuclear system penetrates the control room). The sensor cables and logic power supply cables are routed to cabinets in the auxiliary equipment room, where the system logic is located. All instrument line penetrations of the containment are equipped with automatic isolation valves. These excess flow check valves automatically isolate if there is a break in the instrument line downstream of the valve. 7.3.1.1.2.4 PCRVICS Initiating Isolation Signals C. The isolation trip settings of primary containment and reactor vessel isolation control system are listed in Chapter 16. The functional control diagrams (Figures 7.3-7, 7.3-8, 7.3-10, 7.4-1, 7.7-11) and the P& ids (Figures 5.1-3, 5.1-4, 5.4-16, 5.4-13, 5.4-8, and 6.3-7) illustrate how these signals initiate closure of isolation valves. Additional logic is shown in Figures 7.3-14, 7.3-15, 7.3-16, 7.3-18, 7.3-19, and 7.3-20. 7.3.1.1.2.4.i PCRVICS - Reactor Vessel Low Water Level 7.3.1.1.2.4.1.1 Subsystem Identification A low water level in the reactor vessel could indicate that l reactor coolant is being lost through a breach in the RCPB and that the core is in danger of becoming overheated as the reactor coolant inventory' diminishes. Three reactor vessel low water level isolation trip settings are used to complete the isolation of the primary containment and the / reactor vessel. The first (and highest) low water level setting level 3 (which is the RPS low water level scram setting) is selected to initiate isolation at the earliest indication of a possible breach in the RCPB, yet the setting is far enough below normal operational levels to prevent spurious isolation. The pipelines that are ((- isolated when reactor vessel low water level falls to level 3 are l 1RHR shutdown cooling and RPV head spray. 7.3-33 Rev. 18, 03/83 .t
l LGS FSAR ) The second (middle) reactor vessel low water level isolation setting (level 2) is the same water level setting at which the RCIC and HPCI systems are placed in operation. The setting selected is low enough to allow the removal of heat from the reactor for a predetermined time following the scram and high enough to complete isolation in time for the operation of ECCS if there is a large break in the RCPB. The pipelines that are isolated when the reactor vessel water level falls to this second setting are listed below. a. Reactor water cleanup b. Containment atmospheric control including H,0, sample lines c. Traversing incore probe d. Main steam sample e. HPCI pump flush f. RHR vacuum relief g. Drywell sump drains j h. Suppression pool cleanup l 1. Drywell radiation sample j. Drywdl skuled Me ple Recirculation loop sam k. The third.(and lowest) of the reactor vessel low water level isolation settings (level 1) is the water level setting used to initiate RHR, core spray, and automatic depressurization system, and to start the diesel generators. The pipelines that are isolated when the reactor vessel water level falls to this third setting are the main steam, main steam line drain, containment instrument gas, RHR heat exchanger vent valves, suppression pool spray and core spray pump test and flush. Reactor vessel low water level signals are initiated from eight differential pressure sensors, four sensors for the level 1 and level 2 trip and four sensors for the level 3 trip, as shown in Figure 5.1-4. They sense the difference between the pressure caused by a constant reference leg of water and the pressure caused by the actual water level in the vessel. Four pairs of instrument sensing lines, attached to taps above and below the water level on the reactor vessel, are required for the differential pressure measurement and terminate outside the drywell and inside the reactor enclosure. They are physically Rev. 18, 03/83 7.3-34
LGS FSAR 7.3.1.1.2.4.6.3 Subsystem Initiating Circuits Drywell pressure is monitored by four pressure sensors that are mounted on instrument racks outside the primary containment. Instrument sensing lines that terminate in the reactor enclosure connect the sensors with the drywell interior. Redundant sensors are physically separated and electrically connected to the isolation control systems so that no single event prevents t isolation because of primary containment high pressure. 7.3.1.1.2.4.6.4 Subsystem Logic and Sequencing When a predetermined increase in drywell pressure is detected, trip signals are transmitted to the PCRVICS. The PCRVICS isolates the following lines drywell drains and drywell sump drains discharge to radwaste, primary containment purge and vent, traversing incore probe (TIP) system, containment atmosphere sampling, containment instrument gas, vacuum relief, HPCI pump ool flush and vacuum relief, RCIC vacuum relief, suppressio.n p/gr, cleanup, ensk drywell radiation sample, and drp(A eMjr.d ge Four instrumentation channels are provided to ensure protective -(- action when required and to prevent inadvertent isolation resulting from instrumentation malfunctions. The output trip sigraals of the instrumentation channels are combined in two-out-of-two logics. Instrumentation channels A and B or C and D are required to initiate isolation of either inboard or outboard valves, respectively. Thus, failure of any one channel does not result in inadvertent action. 7.3.1.1.'2.4.6.5 Subsystem Redundancy and Diversity Redundancy of trip initiation signals for drywell high pressure is provided by pressure switches installed at different locations around the drywell. Wiring from redundant instruments is separated. Each pressure switch is associated with one logic I division. Two pressure sensors are supplied from RPS bus A, and the other two are supplied from RPS bus B. Diversity of trip initiation signals for line breaks inside the primary containment is provided by drywell high pressure and reactor low water level. An increase in drywell pressure or a decrease in reactor water level initiates isolation. 7.3.1.1.2.4.6.6 Subsystem Bypasses and Interlocks There are no bypasses or interlocks for drywell high-pressure trip signals. 7.3.1.1.2.4.6.7 Subsystem Testability 7.3-39 Rev. 16, 01/83
~ ~~ ! _.. _ ;. ~ NO cho. LGS FSAR l isolation. Redundant channels for each monitored variable provide inputs to different isolation trip systems. The functions of the sensors in the isolation control system are l shown in Figures 7.3-1 and 7.3-2. Table 7.3-5 lists instrument characteristics. 7.3.1.1.2.6 PCRVICS Initiating Circuits The valves which are controlled by the PCRVICS for i automatic isolation generally utilize actuator solenoids which are energized during normal service. The logic circuitry signalling automatic isolation is generally arranged such that when a monitored parameter reaches its trip setpoint, the associated trip logic contact opens. When the proper combination l of logic trips occur, the actuator trip relay de-energizes. de-energizing the valve actuator solenoid. The system also has system level manual initiation switches that isolate all automatically controlled isolation valves. This general arrangement is applicable to the following valve discussions. The MSIV actuators ehch have two actuator solenoids. For automatic valve closure, both solenoids must be de-energized. Each solenoid receives inputs from two separate division logics, either of which can de-energize the solenoid. Four RPS instrument channels are provided for each monitored parameter used in the MSIV trip logic. The redundant instrument channels are independent and separate. Channels A and C actuator logic trip relays control one solenoid in each of the inboard and outboard MSIV's on each main steam line. Channels B and D actuator logic trip relays control the other solenoid in the inboard and outboard MSIV's. Closure of the inboard and outboard main steam line drain isolation motor-operated valves is initiated by the MSIV actuator logic trip relays, utilizing two-out-of-two logic. Logic relays A and B initiate clcture of the inboard isolation valve and relays l C and D initiate c'losure of the outboard isolation valve. Closure of the inboard and outboard RHR discharge to radwaste isolation valves and RHR process sampling isolation valves is initiated by low reactor vessel water level and high drywell pressure signals, utilizing two-out-of-two logic. Logic trip relay A closes the inboard valves and logic trip relay B closes the outboard valves. Closure of the inboard RHR shutdown cooling suction and inboard RHR head spray isolation motor-operated valves, as well as the RHR shutdown cooling injection-testable check valve and bypass valve is initiated by logic trip relay A.' Closure of the outboard RHR shutdown cooling suction, outboard RHR head spray isolation, and Rev. 18, 03/83 7.3-44
J - --. ~ ~ ~~ j....... LGS FSAR M ..HR shutdown cooling injection outboard throttling motor-operated valves is initiated by logic trip relay B. Tripping of the logic trip relay requires tripping of the two-out-of-two logic for low reactor vessel water level signal or the one-out-of-two logic for reactor low pressure signals. Closure of the inboard and outboard reactor water sample motor-operated valves and reactor steam sample air-operated valves is initiated by low reactor vessel water level and high steam line radiation signals, utilizing two-out-of-two logic. Logic trip relay A closes the inboard valves and logic trip relay i B closes the outboard valves. Retraction of the TIP drives is initiated by low reactor vessel water level 2 and high drywell pressure in a two-out-of-two logic. Logic trip relay A initiates retraction of the TIP system drives. Closure of the primary containment purge valves is initiated by any one of the following conditions in a two-out-of-two logic: reactor level below level 2 trip; high drywell pressure; high radiation in the reactor enclosure ventilation exhaust duct; high radiation in the refueling floor ventilation exhaust duct. l (- Closure of the inboard and outboard RWCU isolation motor-operate 3 valves is initiated by low reactor vessel water level utilizing two-out-of-two logic or by high area temperature and high differential RWCU flow utilizing one-out-of-one logic. Logic trip relay A closes the inboard valve and logic trip relay B closes the outboard valves. Closure of the inboard containment instrument gas system (CIGS) suction valve is initiated by any one of the following conditions in a two-out-of-two logic: Reactor level below level 1 trip; high drywell pressure; high radiation in the reactor enclosure ventilation exhaust duct; or high radiation in the refueling floor ventilation exhaust duct. Closure of the primary containment atmosphere sample isolation valves and the post-LOCA hydrogen recombiner isolation valves is initiated by any one of the following conditions in a one-out-of-- one logic: Reactor level below level 2 trip; high drywell pressure; high radiation in the reactor enclosure ventilation exhaust duct; high radiation in the refueling floor ventilation exhaust duct. Closure of outboard CIGS isolation valves not on ADS gas supply lines is initiated by any one of the following conditions in a {, two-out-of-two logic Reactor level below level 1 trip; high drywell pressure; high radiation in the reactor enclosure ventilation exhaust duct. 7.3-45 Rev. 16, 01/83 . L
hW / Yd Mdh e isolation valves is initiated by any one of the following conditions in a one-out-of-one logics Reactor level below level 2 trip; high drywell pressure; high radiation in the reactor enclosure ventilation exhaust duct; high radiation in the refueling floor ventilation exhaust duct. e ee -.e 9 m
IAS FSAF i TABLE 7.5-3 (cont'd) (Page 3 Et 2SI INDICATION [ TYPE / t ITEM 9 CATEGORY INS 11tOMI!NT VARIABLES ts3 t13 TYPE M INSTRUMENT RANGE NO. (DIV. I IACATION ji containment Isolation Valve Position B10 1 BV13-106 Indicating 1 pair per open/ closed RS13-106 Control roces lights talve (Div III) BV13-107 Indicating 1 pair per open/ closed MS13-107 Control room l lights valve (Div III) V26-190A, C Indicating 1 open/ closed MSC lights Control rGoa lights (Div III) SW26-1908, D Indicating 1 open/ closed MSC lights control room lights (Div II) HV40-1F0018, F, Indicating 1 pair per open/ closed RS40-1105,F Control room R, P lights valve K,P (Div II) i HV41-1F022A, B, g Indicating 1 pair per open/ closed RS41-122A, B Control room C, D lights ' valve C,D (Div I) RV41-1F028A, B, Indicating 1 pair per
- Open/ closed RC41-128A, Be Control room C, D lights valve C, D (Div II)
RV41-1F016 Indicating 1 pair per open/ closed RS41-116 Control room lights valve (Div I) HV41-1F019. Indicating 1 pair per open/ closed MS41-119 Control room lights valve (Div II) RV41-109A, B Indicating 1 pair per open/ closed RS41-109A, B Control room lights valve (Div I) HV41-133A Indicating 1 pair per open/ closed BS41-133A ' Control room lights valve (Div I) HV41-1338 Indicating 1 pair per open/clased RS41-1335 Control room lights valve (Div III HV41-1F084 Indicating
- 1. pair per open/ closed MSr,1-106 Control room lights valve (Div Il
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ICS FSAR TA%LE 7.5-3 (cont'd) (Page 12 ct 2S) INDICATIDM TYPE / ITEM # CATEGORY INSTRUMEWF VARIABLES E*8 513 TYPE M INSTRUMENT RAN3E NO. (DIV. ) LOCATIQW i: EV59-131 Indicating 1 open/ closed RS59-131 Control room lights (Div II) HV59-101 Indicating 1 open/ closed RS59-101 Control room t lights (Div I) i HV59-102 Indicating 1 pair per open/ closed NS59-102 control room lights valve (Div II) XV59-141A, B, Indicating 1 pair per open/ closed valve control control room C,D,E lights valve monitor R, B, C, D, E i BV59-135 Indicating 1 pair per open/ closed HS59-135 Control room lights valve (Div II) HV61-102, 112, Indicating 1 per valve open/ closed ES61-112 Control room 132 lights (Div I) \\; HV61-110 Indicating 1 open/ closed MSC lights Control room lights (Div I) t' l HV61-130 Indicating 1 open/ closed NSC lights Control room lights (Div II HV61-111 Indicating 1 open/ closed MSC lights Control room lights (Div III HV61-131 Indicating 1 open/ closed BS61-131 Control room (Div II) lights ?"@ BV87-128,129 Indicating 1 Aper open/ closed MS87-128. Control room lights valve (Div II) Palp + BV87-122,123 Indicating 1 Aper open/ closed MS81-122 control room lights valve (Div II) $V87-120A it:4' T^dEddf Iposhper opeA/6 H567-It'A &h}w itq4hgg Ii kh volt (DW 3) 9 zrd EdlNM l PNP Por dFE^!CfMt M" RN b liqMS vM (bh d me,, i., oif 3 )
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NO LGS FSAR (~ OUESTION 480.26 (Section 6.2.3) Supplement your description of containment bypass leakage barriers listed in FSAR Table 6.2-15 in the following areas: a. Penetrations X-23, 24, 53, 54, 55, and 56 rely on closed systems inside containment to preclude bypass leakage. Verify that each requirement listed in Branch Technical Position (BTP) CSB 6-3 Position B.9 is met for these systems. b. Provide additional information describing the feedwater fill system and demonstrate that it conforms to the NRC guidelines commensurate to its safety function of eliminating bypass leakage (reference BTP CSB 6-3 Position B.8). c. For all containment penetrations in FSAR Table 6.2-15 that rely on a water seal to prevent bypass leakage, provide additional information that demonstrates the ( water seal will be maintained for 30 days following a
- LOCA, i.e.,
that the water seal is maintained at a pressure greater than the peak containment accident pressure and that a sufficient water seal inventory to last at least 30 days following a design basis acccident is provided. d. The recirculation pump seal purge lines (Penetration X-
- 61) are vented to secondary containment by use of vent lines located before two block valves and the secondary containment (see FSAR Figures 5.4-2 and 4.6-5).
The P&ID shows no automatic actuation signal to the valve operators for the normally closed vent valves (HV125 and HV126) or the normally open block valves (HV127 and HV128). Verify that these valve operators will receive containment isolation signals to open and close, respectively. e. FSAR Table 6.2-15 indicates that the HPCI and RCIC vacuum relief lines (Penetrations X-228D and 241) contain temporary spool pieces that are removed during normal operation and replaced by blind flanges. These spool pieces are not shown on the P& ids (FSAR Figures (- 6.3-7 and 5.4-8). Provide revised P& ids that include the spool pieces, or describe alternative provisions to preclude bypass leakage. 480.26-1 Rev. 13, 11/82
LGS FSAR ~) NOTE: Any penetration through which bypass leakage cannot be precluded by an acceptably described bypo.ss leakage barrier must be considered as a bypass leakage path and treated as described in BTP CSB 6-3 Positions B.6 and 7.
RESPONSE
Section 6.2.3.2.3 has been changed to supplement the description of containment bypass leakage barriers listed in Table 6.2-15. Each of the above areas has been addressed individually below, Bo h th fdrywe1,I chillpd wa er DCW) sys em ,d a. e C& r cto'r enclosure cooling t ($CW) yst ar snate s iscussion,as/close /syst sj nsi,de co tai entf. assi ied las)if fng Rt d C 'g, isfy rf o the dej c,onta1nWnt is'th J r clyspd sy (tems in lud;e 't ' ) response to esti 80M O. b. Section 6.2.3.2.3 and Table 3.2-1 nave been enanged to provide the requested information. l c. Section 6.2.3.2.3.1 has been added to provide the requested information. d, The normally open block valves (HV127 and HV128) receive an automatic containment isolation signal to close, which is shown as Ref 18 on Figure 4.6-5. It is not necessary for the containment isolation signal to also automatically open the (normally closed) vent valves. The seal lines are normally filled with water, which will spill into secondary containment when the vent valves open. To preclude the possibility of this happening in the event of a false LOCA, the vent valves will be manually actuated to open when the operator has verified that isolation and venting of these lines is i required. The water in the lines will provide a temporary seal to prevent bypass leakage until the vent valves are opened. i e. The temporary spool pieces are on branch lines to the HPCI and RCIC vacuum relief lines. The spool pieces are shown on Figure 6.3-7 (line 4" EBB-108) and on Figure 5.4-9 (line 3" EBB-109). so. Rev. 15, 12/82 480.26-2
. _. 7 ____. _ _ _ _. _. 7%A d elsh5/ad spbe (pse/aA& p t~s n; e, / < a o s a a d- - sh,a s9 ah, sp6 (y /shans s a/sr) ag d /sA ea#4e a usde ses/ sa h e l eo d k / sm/ a/n&d nom /sk ss 4,sa Ads, danve,,. fehoks t u r.y e / a g w e d 72/4s 62-/r, 6.2-/7, m/42-25 jaar &&r 64ry/ b pwa6 abirwdrn ameeromy -46se dgNaks/ l sa As/sp da/aa. y
s ~~ LGS FSAR (9 OUESTION 480.40 (Section 6.2.4) It is the NRC position that the requirements of GDC 56 and not GDC 57 Rust be met for the instrument gas supply lines (Penetration X-3B, X-3D, X-40H, and X-218), the recirculation pump cooling water supply and return lines (Penetrations X-23 and X-24) and the drywell chilled water supply and return lines (Penetrations X-53, X-54, X-55, and X-56) because the systems inside containment to which these lines connect do not meet the requirements of a closed system (see SRP Section 6.2.4 Item II.o and FSAR Section 6.2.4.3.1.6). Therefore demonstrate for these penetrations how the containment isolation requirements of GDC 56 will be met. (Note: For the instrument gas line penetrations, GDC 56 requirements will be met if both the cutside valves (HV129B, HV151, ilV129A, and HV135) and the inside check valves N (1005B, 1112, 1005A, and 1001) are included in FSAR Table 6.2-17 as containment isolation valves for Penetrations X-3B, X-3D, X-40H, and X-218, respectively). I
RESPONSE
i [ Section 6.2.4 and Tables 6.2-17 and '1-3 have been changed to l verify that the requirements of GDC 6 have been met for the instrument gas supply lines (Penetrations X-3B, X-3D, X-27A, X-40H, and X-218). ) sb k ti ( [*9 . ater (RECW) system form closed systems inside c w conta. nt,that meet the requirements of 10CFR part 50, Appendix ' General Design Criteria 54 and 57 and the ent of the guidelin i n.SRP Section 6.2.4, item II.O. T J 'hystems j hmE uave been desig 'with the following isolation p_ visions: ~ close as practi(ca ' A least one O a. tion valve is p ed on each line as l a. o the cont ent b. The isolation valves a "a le of remote manual operation l Ns c. Power supplies an 4 ontrols for
- isolation valves are safety grade ms from containment to, and %. luding, the d.
Piping syy~ isolatonvalvesaresafetygradeandqua(lltcgoupB. c I-e. systems do not communicate with either the 4pctor oolant pressure boundary or the containment atmosphere 480.40-1 Rev. 15, 12/82
4 0 j l o LGS FSAR discussed in Section 3.2.1, and have been desig .o the 'same seismic loads as. seismic Category I syste g. RECW and DCW systems have been designed 'Ouality G p C and D standards, respectively. The quality st ards are supplemented by quality cont 1 ins tions by trained and qualified insp. ors that l perf . and document inspections on pip insta tions, welds, valves, and hang These system re designed with fully welde,oints between interco ecting piping and use the s materials that are used Safety Class 2 piping s ems 3 l h. The system ave been designed to - thstand the external l pressure fr the containment st.ctural acceptance test and use mate als capable of wi tanding temperatures j in excess of e containment d gn temperature l i. These systems 'not connect the environment except l through a vent i 'the syste. head tanks. WM 1 l The probability (of a releas a.to th jenvironment through these closed systems b low. For
- rel se to the environment to occur, it 35 necessary to ass e.
11 of the following: wM a. Loss-of-coolant acci a b. Core damage f c. Failure of the c: sed syst ,inside containment gf ) 4 d. Failureofthegontainmentiolationvalves ,- --I c t i y-tion v k ulvec ;!nc Q oard e. m h.ure et t es ves) o The design of the ystems and their cont'i,nment isolation provisions are ir ccordance with the desi n;_ commitments made in . as well as industry and NR aguidance available the Limerick PS f at that time, f The-close sfstems are seismic Cateaory TTA. adsitscussed 7 ~ g i Section 3.2g1, anWVetEen-desk ned tn the sam *;noimmir, loads J ory l jystems. p The prodbility associated with a closed system %aik. x-f ure resnit f.ng-- in a rflease to the environme h - r-e-relea .to the envi Onment, it is nece assume a t .in both cor fdamage a osed system pipe break inside con hTa'n" g ;ya,1v fallge3 n2 g 1osedfsysg. Rev. 15, 12/82 480.40-2
f LGS FSAR ition, system isolatio M >e . W.ovi conta or-eactr crosed Tpsi.em. Th -are _re g;tt oe e c ntr if6em is alsch prov 4 t. O indicators in the control room. In addition, the D ^ -e 0. t a time (either pen - -53'and X-54 or - - 6). re alves are normally closed. A A 2 n I Y b Y end' SW fftf7bm k u da.e & n day / A m / 4 yaunA of hb$ Eb-l b $ W pry / $ $ faf-/7 bd ~ du edangd d sidh4 i!$ amp she. h l A ksts 4-l l l l 1 480.40-3 Rev. 15, 12/82 _r.--- - - - -
j L, W%% ! The appl &,t hai not. provideUM&fpt* ah6ults of an anafpis s hich ~~ l demAstrates'the accept'abihty of the provisions made 16 protect strpres and- .4 saf ety related eqsipment (e.g., fans. Liters, and ductwork) secated bevond tbe, l pacpe system containment isolation valves agtainst. Joss et. function from ti
- enrirement cecated by' escaping air and steam follombg s LOCA. in accordaree
-~
- sirb FTP CSB 6-4 Position B.S.b., Sefecence DEC Question 480.42 Part h.-
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480.42(h)
Response
The Limerick containment purge and vent valves will be opened for afimitedperiodoftimeduringpoweroperationfor.inertinganddeinerting of the primary containment atmosphere. The inert atmosphere,,(cliluted with nitrogen to < 4*. 0;) is purged from containment in anticipation of outages requiring containment acces's to allow inspections and limited repairs while the reactor is at some reduced power level. Inspections are also performed during power ascention prior to the inerting of <.ontainment. These inspections facilitate the early detection and 1,ocation of coolant systein leaks which could have an impact on v. nit reliability and safety if uncorrected. The Containment Atmosphere Control System is described in Section 9.4.s '. and illustrated i'n Figure -9.4-5." Purging and venting operations are,normally, l j performed through one 24": supply penetration and one 24" exhaust penetra'tlon. All gases purged from cont'ainment are processed through SGTS prior to' release. Because the purge and vent valves are opened during only a limited period of power operation (typica'lly less than 90 hours per year), it i's unlikely that a LOCA will occur whil.e the valves are open. If a LOCA were to occur during this time, the containment isolation valves would close rapidly (less than 6 seconds after receipt of isolation signal) and terminate the release. Isolation will be complete long bef, ore any fuel damage or significant offsite exposure could occur. The containment isolation valves d.l: Sed
- have been specially designed arid qualified for this service 'as described in Section 9.4-5.
It is possible in such cases, however, for the downstream eldwo4. W/m-SGTS T h s... -y . +,.. .-,,,--,y ,y- .,-,-,.,r, ,-,--,w. r_.,-- -,-,,.4--.
~ to be damaged by the pressure surge. preceeding valve closure and/or the moisture content of the released gases. Anal'yses have been performed to determine the potential for, and sign'ificance of, the above described seluence of events at Limerick. - l i - Ca1culations indicate that the design pressure of the ductwork and ~ the design differential pressure of the SGTS filters be exceeded A if the %A LOCA occurred during purging. This could (1) result in the failure of the operating SGTS filter bank, and (2) possibly cause. equip e t failures in the Reactor Enclosure due to duct impact, im-pingement, and/or the resulting environmental conditions. Failure of the operating SGTS filter bank is of little significance due to the limited benefit derived from SGTS for accident sequences related to plant' risk and the possibi.lity that' the backup filter bank would be operabie[ The r'.esults 'of the Ifeactor Safety Study (see WASil-1400; Table 5-3) indicite that the fai,2ure 'of SGTS du' ring a LOCA does not con-- tributetoanysignificant' release'sihaBWRf'orthefollowingreas'ons: c l LOCA sequences contribut'e little to radioactive-releases relative to transien't sequences. Consideration of SGTS failure is only relevant \\ for small cont,ainment leaks (i.e. - compared with a containment overpressure rupture). I ~ Because of the potential significance of equipment failures, cal-l culations and detailed equipment location surveys have been, performed s' l
for Limerick to verify that (1) the environmental qualifications for the LCS equipment are sufficient to " assure operability under the t predicted environmental condit, ions.,- (2) the potential does not i exist for impact or impingement rel'ated damage to essential equipment. olJe k/ .The above described conclusions appigwith significant con- 'servatism,jto the situation when either a medium or small LOCA is postulated to occur during purging. For a small LOCA, the ductwork is not expected to rupture, and the SGTS heaters can lie expected to reduce the relative humidity of the incoming gases. For a medium LOCA, if the ductwork should rupture, the amount of steam released ealoswC into t'he reactor buiMir.g and the energy available for impact or A impingement will be considerably less than that associated with a .kh\\.LOCA. g g
,453taL\\m CSB's fdQfings on the applicant's compliann with "BTP CSB 6-4, tontairlment Purging Daring Normal Plant Operations," is contingent on the acceptance of the valve operability assurance program for both high and low volume drywell and suppression chamber purge system line containment isolation valves by the f Equipment Qualification Branch (EQB). (Contingency) l l r h \\ be4h_LML I % ) p A, A _ w A 4 M. s_ayLi. \\ Nec_ M AMA M- _ ?W_ A j T x _n _g A M ___ A d h A Lu_ W _ALLd b 1 _m_M.4_ f .n f _. S A n ttd k sti_ vec. [ 4_ M _ p M _g 9z3,19e e. ~
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II s lt il li a 7-ll Containment isolation valves HV-109A-and HV-109B (feedwater line penetrations X-9A and X-98, respectively) must be s'ealed dosed as defined in 5RP 5ectlen 6.14 ~v ILf. (Note: This is a new issue resufting from the F5AR-Revision 16 chnge.In-footnote (13) of Table 6.2-17, page 19 of 19. The previous applicant's statemen't revised to simply
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s I l LGS FSAR b' containment isolation barriers, are\\, maintained. All ~ power-operated isolation valves have position indicators in the l control room. Discussion of instrumentation and controls for the l isolation valves is included in Chapter 7. 6.2.4.3.1 Evaluation Against General Design Criteria I 6.2.4.3.1.1 Evaluation Against General Design Criterion 54 All piping systems penetrating containment, other than instrument lines, are designed in accordance with Criterion 54. 6.2.4.3.1.2 Evaluation Against Criterion 55 Criterion 55 requires that lines which penetrate the primary containment and form a part of the RCPB must have two isolation valves; one inside the containment and one outside, unless it can be demonstrated that the containment isolation provisions for a specific class of lines are acceptable on some other basis. The RC'PB, as defined in 10 CFR Part 50, Section 50.2 (v), consists of the reactor pressure vessel, pressure retaining appurtenances attached to the vessel, and valves and pipes that extend from the reactor pressure vessel up to and including the outermost isolation valve. ) 6.2.4.3.1.2.1 Influent Lines Influent lines that penetrate the primary containment and connect directly to the RCPB are equipped with at least two isolation valves, one inside the drywell, and the other as close to the external side of the containment as practicable. l 6.2.4.3.1 2.1.1 Feedwater Line The feedwater line is part of the RCPB as it penetrates the drywell to connect with the reactor pressure vessel. It has three isolation valves. The isolation valve inside the drywell i is a check valve located as close as practicable to the containment wall. Outside the containment is hn air-assisted check valve located as close as practicable to the containment wall, and farther away from the containment is a m6 tor-assisted check valve on the feedwater line. Additional isolation valves are located on lines connecting to the feedwater line outside containment.A Should a break occur in the feedwater line, the l W outboard check valves prevent significant loss of reactor coolant inventory and offer immediate isolation. (It is impractical to e L 'l restrain the inboard check valve to withstand pipe whip resulting from a downstream feedwater line break; therefore it cannot be assumed to isolate for this case.) During a postulated LOCA, it is desirable to maintain reactor coolant makeup from all sources of supply. For this reason, the feedwater lines are not Rev. 16, 01/83 6.2-48
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=_. O cMy LGS FSAR 1 automatically isolated upon signals from the protection system. The outermost valve is. capable of being remotely closed from the control room to provide long-term leakage protection. The air-assisted check valve is provided with a special actuator that performs the following functions: a. The actuator is capable of partially moving the valve i disc into the flow stream during normal plant operation in order to ensure that the valve is not bound in the l open position. The actuator is not capable of fully closing the valve against flow, however, and there is no significant disruption of feedwater flow. b. The actuator is capable of applying a seating force to i the valve at low differential pressures and abnormal conditions. This improves the leaktightness of the valves. The actuator is not utilized during leak testing. 6.2.4.3.1.2.1.2 HPCI Line The HPCI line connects to CS loop B'that penetrates the drywell j to inject directly into the RPV. Isolation is provided by two valves in the CS line, an air testable check valve inside the containment, and an air assisted check valve outside the containment, with positions of both indicated in the main control room. The core spray loop B line is also provided with a normally closed motor-operated globe valve which bypasses the inboard isolation valve for equalization during testing. 6.2.4.3.1.2.1.3 LPCI and CS Loop A The LPCI lines and CS loop A line are provided with remote l manually controlled gate valves outside and air testable check valves inside containment. Both types of valves are normally closed with the gate valves receiving an automatic signal to open at the appropriate time. The check valves are located as close as practicable to the RPV. The normally closed check valves protect against containment pressurization if t'here is a pipe rupture between the check valve and containment wal.1. The core spray loop A line and the LPCI lines are also each provided with a normally closed motor-operated globe valve which bypasses the inboard isolation valve for testing purposes. 6.2-49 Rev. 16, 01/83 - ___- _ ___ _ _ - - - - -, -._ ~...-..
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s LGS-FSAR TABLE 6.2-17 (Cont'd) (Page 19 of 19) (12) Only non-essential systems require diverse signals for automatic isolation. Therefore, this column is not applicable, (NA), for essential systems. sed.d (13) These valves are normally closed and will only l E-be opened Nn nf the f =& &e s oy sr@fd ec centro res ri tiid t aw rr. Glcrure ti== --ice: err 60 re. %,srLumetis incletion sig.cla Le Line=, W e =ra tterefere net required. (14) Diverse is lation signals are not sensed as discussed in Section 6.2.4.3.1. (15) These val es are normally closed, will be open only during re ctor shutdown, are interlocked to open only on low r actor pressure, and connect to a closed system outside containment. Therefore, closure times less than 6 seconds are not required. b y (r a ga s e =~* 1 1 T1001550-01V Rev. 16, 01/83 ,}}