Text

Forwards marked-up Revs to Facility FSAR Containing Text Changes Due to Resolution of Various SER Outstanding & Confirmatory Items,Revs to Maintain Consistency W/Tech Specs & Revs to Reconcile as-built Plant Discrepancies
	ML20138A994
Person / Time
Site:	Hope Creek
Issue date:	03/17/1986
From:	Corbin McNeil; Public Service Enterprise Group
To:	Adensam E; Office of Nuclear Reactor Regulation
References
	NUDOCS 8603200242
	Download: ML20138A994 (109)
	v • d • e

{{#Wiki_filter:- Pubhc Service Electric and Gas Cornpany Cerbin A. McNeill, Jr. Pubhc Service Electric and Gas Company P.O. Box 236, H ancocks Bridge, NJ 08038 609339-4800 Vice Pres # dent - Nuclear March 17, 1986 Director of Nuclear Reactor Regulation United States Nuclear Regulatory Commission 7920 Norfolk Avenue Bethesda, Maryland 20814 Attention: Ms. Elinor Adensam, Director Project Directorate 3 Division of BWR Licensing

Dear Ms. Adensam:

FINAL SAFETY ANALYSIS REPORT REVISIONS HOPE CREEK GENERATING STATION DOCKET NO. 50-354 Public Service Electric and Gas Company (PSE&G) hereby submits various revisions to the Hope Creek Generating Station (HCGS) Final Safety Analysis Report (FSAR). The attached revisions to the HCGS FSAR contain:

1) text changes due to the resolution of various Safety Evaluation Report (SER) Outstanding and Confirmatory Items; 2) revisions

.to maintain FSAR consistency with the Technical Specifications;

3) revicions to reconcile as-built plant discrepancies; and 4) general changes to the FSAR text, tables and figures. provides a brief summary and explanation for each change while Attachment 2 contains the actual marked-up sections of the FSAR.

These revisions will be incorporated in FSAR Amendment 15 after fuel load but are being filed now in order to accurately reflect the design and operation of HCGS and support the issuance of an operating' license. In addition, an affidavit is provided to affirm that the matters set forth in this transmittal are true and accurate. This submittal supplements a similar transmittal from C.A. McNeill to E. Adensam dated March 3, 1986. 8603200242 860317 0 PDR ADOCK 05000 4 h0 8 I

Director of Nuclear 2 3-17-86 Reactor Regulation Should you have any questions on the subject filing, do not hositate to contact us. Sincerely, Affidavit Attachments (2) C D.H. Wagner USNRC Licensing Project Manager R.W. Borchardt USNRC Senior Resident Inspector

UNITED-STATES OF AMERICA NUCLEAR REGULATORY COMMISSION DOCKET NO. 50-354 PUBLIC SERVICE ELECTRIC AND GAS COMPANY FINAL SAFETY ANALYSIS REPORT REVISIONS 4 Public Service Electric and Gas Company (PSE&G).hereby submits various revisions to the Hope Creek Generating Station (HCGS) Final Safety Analysis Report (FSAR). These HCGS FSAR revisions consists of text changes due to resolution of various Safety Evaluation Report (SER) Outstanding and Confirmatory Issues, revisions to maintain FSAR consistency with the Technical Specifications, revisions to reconcile as-built plant discrepancies, and general revisions to the FSAR text, tables and figures. The matters' set forth in these revisions are true and accurate to the best of my knowledge, information, and belief. Respectfully submitted, Public Service Electric and Gas Company By: NNN Corbin A. McNeill, tnt. Vice President - Nuclear Sworn to and subscribed before me, a Notary Public of New Jersey,z this /7 68 day of March 1986. DELORIS D. HAD001 A Notary Putdic of New Jersey My Commiss% Ermres Much 14,1990

ATTACHMENT l-

SUMMARY

OF CHANGES, ADDITIONS AND/OR MODIFICATIONS 1.10.2 Revision references 10CFR50.73 which -(II.K.3.17) discusses licensee event reports. 3.10.1.1.1 Revisions are necessary to refer $nce 3.10.2.1 .the appropriate IEEE standard and to show 3.10.2.1.1 recommended changes according to the 3.10.2.1.2 SQRT seismic methodology. 3.10.3.1 T3.10-3, pg. 1,3/6 T3.ll-4, + Revisions on pages 20, 54 and 72 were pg. 20,51,53, submitted.to the NRC via a letter from 54,72/83 PSE&G on February 25, 1986 - The Environmental Qualification Summary Report, Rev. 4-while pages 51 and 53 have been revised to include the amendment date, on the bottom of the page, when they were published. T3.ll-5, Revisions add the feedwater cross-tie pg. 30/119 isolation valve, HV-4144, but exempt T3.11-6, it from Environmental Qualification pg. 2/3 requirements since the valve has double breaker isolation and is not essential for a pipe-break outside the drywell. Flooding of this valve by a feedwater line break in the steam tunnel does not affect the shutdown capability of the plant. T3.ll-6, Revisions add and delete various equipment pg. 1,2,3/3 to reflect information contained in the main steam tunnel flooding analysis. These revisions are consistent with Technical Specification Table 3.8.4.6-1 and supercede those provided to the NRC in a letter from C.A. McNeill to E. Adensam dated March 3, 1986. 4.6.1.2.4.2.a Revision changes the condensate. water pump suction filter absolute rating i to reflect vendor documents. 5.4.6.2.5.1.r Revision interchanges the valve tag numbers E51-LV-F005 and E51-HV-F004 to reflect the as-built plant conditions. i ,, ~.,- -,.

2 T5.4-2 Revisions change the setpoints for various RHR relief valves to reflect as-built plant' design and delete the entries which are part of the steam condensing mode as the_ system is isolated by weld neck blind flanges. F5.4-2. Revisions change the normal valve position sh. 1/2 for the reactor recirculation water 6.2.4.3.1.10 sample line from closed to open in T6.2-16 order to comply with Technical Specification pg. 3/33 3/4.4.4 which requires continuous sampling. 6.2.4.3.1.2 + Revisions clarify the feedwater line 6.2.4.4.3 classification and testing as a result 6.2.6.3 of the withdrawl of Appendix J Exemption T6.2-16, Request #4. These revisions were previously pg. 1,33/33 submitted by C.A. McNeill to E. Adensam T6.2-24, on March 11, 1986. pg. 1/17 F6.2-28, sh. 2/48 6.2.4.3.5 Revisions to these sections are necessary 6.3.2.8 since an overly restrictive commitment exists requiring the locking closed of over 200 test, vent and drain valves. Per Question 480.20, the NRC indicated that SRP 6.2.4 requires branch lines from closed systems to be valved off and under administrative control. Hence the revisions are consistent with the SRP requirements. In' addition, the revisions-were confirmed with Mr. D. Wagner (NRC Project Manager) via phone call on January 7, 1986 and are consistent with the controls that are applied to those valves that are actually part of the primary containment pressure boundary. T6.2-26 Revisions provide information on various sh. 2,3/3 relief valves which have been inadvertently left out of the table. F6.2-45-48 These figures identify the extended containment boundaries for various systems. Changes to these figures are made to be consistent with Table 6.2-16; however, it is no longer necessary to revise these figures everytime a P&ID is updated since the P&ID is reproduced in the FGAR on another figure. The P&ID cross-reference is retained to assure proper source documentation.

w 3 6.4.2.2.e Revision provides additional text for clarity. 6.4.3.2.b Revision necessary to maintain consistency with Section 6.5.1.1.2. 6.4.4.l' Revision clarifies the: comparisons between HPCI line breaks and main steam line breaks and~are consistent with Tables 3.6-4, pg. 3/3, 12.2-7 through 11 and 15.6-14, as well as Section 15.6.4.5.1.2. 6.4.7.1.2 Revision corrects editiorial error .and is necessary to maintain consistency with Section 6.4.7.1.1. 6.4.7.2 Revision necessary to correct editorial inconsistency. 6.8.1.1.a Revision necessary to maintain consistency - with Tables 6.2-12 and 6.8-1. 9.1.3.2.4 Revision provides an additional phrase of text which was omitted in the printing process of Amendment 14. 9.1.5.2.2.11 Revision de-rates the capacity of the SACS pumps monorail from 15 tons to 4 tons since, per Section 9.1.5.3.3.11, the heaviest anticipated lift, the SACS pump motor,.is 6160 lbs. F9.3-9 Revision provides a new figure which shows the sodium pentaborate volume concentration requirements and is consistent with Technical Specification Surveillance 4.1.5.b and Figure 3.1.5-1. T9.5-3, Revision adds nitrogen bottles to reflect pg. 3/5 P&ID M-ll-1, sh. 3/3 (STACS) as the nitrogen is used to control water level in the supply and return accumulators. 11.2 Revisions are necessary to change the ll.2.1.j recycled liquid radwaste (LRW) demineralizer 11.2.2.1.1 effluent water quality limit as it 11.2.2.1.2 is transferred to the CST and normal 11.2.3 makeup to the CST is demineralized water with a conductivity of less than or equal to 1.0 umho/cm (Section 9.2.3). Therefore, a greater quantity.of treated LRW can be recycled without degrading the quality of water in the CST, less treated LRW will have to be discharged from the plant and'less regenerant waste is created due to less frequent regeneration of the LRW demineralizers.

4 11.3.1.e Revision correctly identifies when the continuous radioactivity monitors annunciate in the main. control room. 11.5.2.2.3 Revision deletes seismic requirements from the FRVSV RMS as Regulatory Guide 1.97, Rev. 2 does not require seismic qualification, nor are other portions of the RMS seismically qualified as the system only provides a monitoring function. Tll.5-1, Revisions to various RMS detector ranges pg. 1/6 reflect vendor as-built equipment ranges previously not available. 12.1.3.2 Revisions are necessary to maintain consistency with Section 12.5.1.1. 13.1.2.2.6.a Revision deletes the resume of Mr. Thomas T13.1-4, G. Busch as the individual is no longer pg. 28-31,80, filling the position of Technical ~ Engineer. 114-117/123 As shown in the text, the Senior Supervisors have assumed the responsibility for their areas of expertise. In addition, Mr. William J. Merritt's resume, replaces Mr. Elmer-J.-Galbraith for the position of Senior Technical Supervisor due to personnel changes. Page 80 is editorial. 13.1.2.2.8.e Revisions reflect a recent maintenance F13.1-ll department reorganization which impacts summary statements made in SER Section 13.1.2.l(3), page 13-7, of Supplement 5. 13.1.3.1 Revisions necessary to reflect ANSI /ANS-3.1 T13.1-3, manning criteria and implements various pg. 2/3 training requirements. F13.1-ll 13.2.1.1.1 14.2.12.2 Revision necessary to correct editorial error in Amendment 14. Q430.80 +* Revision deletes the Technical Specification requirements for the cathodic protection system. This issue has been previously addressed in a letter from C.A. McNeill to E. Adensam on January 24, 1986 (Item

53) and impacts SER Section 9.5.4.2, page 9-64.

These revisions impact the SER as noted

+ These revisions have previously been submitted to the NRC by PSE&G in a letter as noted

ATTACHMENT 2 E i i f

HCGS FSAR 01/86 l t The licensees should submit a report detailing outage dates and length of outages for all ECC systems for the last 5 years'of operation, including causes of the outages. This report will provide the staff with a quantification of historical unreliability due to test and maintenance outages, which will be used to determine if a need exists for cumulative outage requirements in the technical specifications. Based on the above guidance and clarification, a detailed report should be submitted. The report should contain (1) outage dates and duration of outages; (2) causes of the outage; (3) ECC systems or components involved in the outage; and (4) corrective action taken. Tests and maintanance outages should be included in the above listings which are to cover the last 5 years of operation. The licensee should propose changes to improve the availability of ECC equipment, if needed. Applicants for an operating license shall establish a plan to meet these requirements.

Response

t All unplanned ECCS outages are documented on. site by incident pocsmagsf recorts, comoleted by the SNSS/NSS. These reports are used to l generate licensee event reports (LERs) in accordance withi __m __m_. _ i c___. 1 Planned ECCS outages are documented in the.7NSS/NSS dail'y log. l Analysis of failure trends is accomplished by means of the LER system, which requires a review of previous occurrences. Identified trends are further analyzed by thelSafety Review Group and/or the Reliability and-Assessment Group. 4 1.10-78a Amendment 14

'~' HCGS FSAR 3.10 SEISMIC OUALIFICATION OF SEISMIC CATEGORY I INSTRUMENTATION AND ELECTRICAL EQUIPMENT The seismic qualification of Seismic Category I instrumentation, electrical equipment, and their supports is described in this section. Sections 3.9.2.3, 3.9.2.4, 3.9.3.2, and 3.9.3.4 address similar topics on the seismic qualification, testing, and analysis of the Seismic Category I mechanical components, equipment, and their supports, including the integral or associated electrical components such as valve-mounted components and pump motors. Dynamic testing methods and-the results of the qualification of active pumps with motors and. supports and pipe-mounted valves listed in Table 3.9-5 are addressed in Sections 3.9.3.2 and 3.9.3.4. All safety-related equipment will be investigated further to demonstrate compliance with the requirements for the seismic qualification review team (SORT) of the NRC. Reports wi11 be submitted to the NRC following the completion of these programs. 3.10.1 SEISMIC OUALIFICATION CRITERIA 3.10.1.1 Seismic Category I Equipment Identification 3.10.1.1.1 Seismic Category I NSSS Equipment Identification, Excluding Motors and Valve-Mounted Equipment Seismic Category I nuclear steam supply system (NSSS) instrumentation and electrical equipment, as well as-other equipment, is identified in Table 3.2-1. All the plant Seismic Category I instrumentation and electrical equipment is qualified to resist and withstand the effects of the postulated earthquakes, jlNSEC'j The Class 12Y:nctrumentatier and 9' supplied by GE and (requiring ciectrical equipmen, excluding a motors and valve-mounted equipmeng,d in Table 3.10-3. seismic qualification are identifie The supporting structures for this equipment are identified in ~ Table 3.10-4. 3.10-1 l

INSERT FOR PAGE 3.10-1 electrical and instrumentation equipment including the condensing chambers which are part of.the pressure transmitter measuring system 1

HCGS FSAR 11/85 demonstrate compliance with Regulatory Guide 1.100. However, the seismic qualification requirements used for this plant ensure an adequate degree of equipment performance and thereby represent an acceptable basis for qualifying the equipment. Some equipment is shown to be qualified by single-axis and/or SEBRT single-frequency testing. However, all essential equipment is A reevaluated \\for seismic qualification according to the requirements or recommendations of IEEE 344-1975, Regulatory Guides 1.92 and 1.100, and Standard Review Plans 3.9.2, 3.10, and HCGS specific requirements as described in Table 3.10-3. ( In most instances, use of single-axis test data is restricted to equipment with response that shows a predominant single mode of vibration in each direction with a minimal cross coupling. In some cases, if the response shows a single mode of vibration in each direction but also has cross coupling, the existing single-axis test data are still used if the test response spectra (TRS) can be shown to exceed the required response spectra (RRS) by a factor of 1.4 over all frequencies. m In most instances, use of single-f'requency test data is k restricted to cases where the required input motion is dominated by one frequency, where response of the equipment is adequately represented by one mode, or where the input motion has sufficient intensity and duration to produce sufficiently high levels of stress to assure structural integrity where structural integrity is the determinant requirement. In some cases, if the input motion is sufficiently high so as to excite secondary modes, such that modal responses can be shown to occur out of phase and at high enough levels, existing single-frequency test data are also used to demonstrate operability. 3.10.2.1.1 Procedures GE-supplied Class lE equipment meets the requirement that the qualification should demonstrate the capability to perform the required function during and after the effects of the safe W3EET shutdown earthquake (SSE). Both-analysis and testinarhre used, 3 but most equipment is tested. Analyses are Or t=:ril?. usefyEE A-determine the adequacy of mechanical strength, e.g., mounting bolts, etc, after operating capability is established by testing as follows: m 3.10-4 Amendment 13

HCGS FSAR 7/85 ~ r a. Analysis - GE-supplied Class 1E~ equipment performing primarily a mechanical safety function, e.g., pressure boundary devices, etc, is analyzed since the passive nature of their critical safety role usually makes testing impractical. Analytical methods sanctioned by IEEE 344-1971 are used in such cases./ See Table 3.10-3

f for indication of which items were qualified by analysis.

b. Testing - GE-supplied Class 1E equipment having primarily an active electrical safety function is tested in compliance with IEEE 344-1971, Section 3.2. 3.10.2.1.2 Documentation Available documentation verifies that the seismic qualification of GE-supplied Class IE equipment is in accordance with the requirements of IEEE 344-1971KSection4. r b 3.10.2.2 Testing Procedures for Qualifying NSSS Electrical e' Equipment and Instrumentation, Excluding Motors and ( Valve-Mounted Equipment The test procedures require that the device be mounted on the table of the vibration machine in a manner similar to the actual mounting condition. The device is tested in the operating states as if it were performing its Class 1E functions. These states A i \\ 3.10-4a Amendment 11

INSERT FOR PAGE 3.10-4 and upgraded using SQRT program methodology INSERT B FOR PAGE 3.10-4 utilizing SQRT program methodology, to demonstrate compliance with IEEE 344-1975. Also analysis to used to INSERT C FOR PAGE 3.10-4a Also, Class lE equipment is analyzed to meet'IEEE 344-1975 utilizing SQRT program methodology. INSERT D FOR PAGE 3.10-4a ( and IEEE 344-1975,

INSERT FOR PAGE 3.10-4 and upgraded using SQRT program methodology INSERT B FOR PAGE 3.10-4 utilizing SQRT program methodology, to demonstrate compliance with IEEE 344-1975. Also analysis to used to INSERT C FOR PAGE 3.10-4a Also, Class lE equipment is analyzed to meet IEEE 344-1975 utilizing SQRT program methodology. INSERT D FOR PAGE 3.10-4a and IEEE 344-1975, I i l l l I l

HCGS FSAR 11/85 The requirements of testing procedures and methods are in accordance with the project seismic specification and with IEEE 344-1975, Section 6. The tests are performed using a combination or one of the following techniques: a. Proof testing b. Fragility testing c. Device testing d. Assembly testing e. Generic testing. 3.10.2.3.3 Combined Analysis and Testing Equipment that cannot be qualified practically by analysis or ( testing because of its size and/or complexity is qualified by combined analysis and testing. Combined analysis and testing methods are in accordance with IEEE 344-1975, Section 7. 3.10.3 METHODS AND PROCEDURE OF ANALYSIS OR TESTING OF SUPPORTS OF ELECTRICAL EQUIPMENT AND INSTRUMENTATION 3.10.3.1 NSSS-Seismic Analysis Testing' Procedures and Restraint Measures The Class 1E equipment supplied by GE is used in many systems on many different plants under widely varying seismic requirements. The HCGS control room panels and local instrument panels are qualified for seismic adequacy by comparison to tested equivalent panels and devices by SQRT program methodology as described in Table 3.10-4. Some GE-supplied Class 1E devices are qualified by analysis only, SESE,J as shown in Tables 3.10-3 and 3.10-4. Analysis is usedtfor passive mechanical devices dnd is sometimes used in combination ( with testing for larger assemblies containing Class 1E devices. \\_ 3.10-8 Amendment 13

INSERT FOR PAGE 3.10-8 for active devices in accordance with SQRT program methodologies and

- = _ ~ . -.. ~ -... = - - _ _ - 1 TD, i 1 o f ( i 4 t HCGS FSAR 11/M5 TABLE 3.10-3 Pace 1 of b i NSSS SEISMIC CATEGORY 1 ELECTRICAL AND INSTRUMENTATION EQUIPMENT QUALIFICATION RESULTS 4 E3ui[ ment Met hod Results Terrerature Elements The temperature elements are The terperature elements designated as havtrq an active qualified by both dy1amic testirg safety turction have been dynamically tested and analysis. The applicable demonstrating qualitication. Mounted simila r to t ield standard is IEEE 344-1975. corditions, they have teen subjected to SPV viDrat ioa aging, chuggir g, seismic, and hydrodyramic loads. Biaxially testirg, over the tregue9cy range or 1 to 4 100 Hz, was accomplished ir three mutually L perperdicular axes with Test Pesponse Spectra frPS) enveloping the Required Peeponse Spectra (PPS). The 4 l temperature elemer ts maintained t heir tunctional and j . structu ral integrity during testirg. I i Those elemerts having a passive safety turction were ar.alyzed to show structural integrity when sub]ected 1 to process pressures ard loade ir excess ot the ] requ irement f or their location. i iemperature Ewitch The temperature switch is showr, The satety tuer. tion of the tenperature switch is i to be qualified by an analysis ' passive. Analysis shows that it exceeds its j of its structural capa bilityp4I structural requiremerts when sunlected to required 76 Mr.EnW,76e6 GuJbGUq seismic. and hydrodyaamic loads, calculatiors irdicate 4 { OF IEE9E 344 - Rh7. a high natural trequr cy makir.q tt a rigid body ir the rarge or interest aad its capahtlity f ar eveeeds its stress requirements. pressure Transmitters; The transmitters are qualified The transmitters can be subjected to both seismic ard Dif f erential, by dynagic testing meeting the hydrodyramic loads duriaq their 1r stalled It te. Absolute, and Gauge guidelines of IEEE 344-1975. Testirg in an as-installed condit ion tr.cluded random 1 treguercy excitation to meet SPV aging, upset and taulted seismic, a9d chugginq requirements. Tests 4 were performed in three mutually perpendicular axes. Durirg testiaq the transmitters maintained structural irtegrity and met turettoral requiremerts. I 1.evel gransmit ters Level trarsmitters are shown to The level trarsmittern have noth an active or passive be qualified for their application saf ety turction deperdi q on their application. Those by both ar.alysis and testing, transmitters with a piestve-satety turction have been Testing was performed to meet the showr to meet structural requirement Dy analys ts. They guidelines of IEEE 344-1975, have natural treguercies niqner that the rarge et i interest and have been snown to have s t ruct ural integrity to withstard the required seismic ard dyramic conditions. 1 j Amendment 1J i

- -.. _. -~..- - - -- - - _ - N j f I HCGS FSAR 11/P5 TABLE 3.10-3 (cont) Page J ot 6 l Insulated Detectors The detectors have been qualified Detectors have an active satety ttinction and ret by dynamic testing to meet structural and tuactioral requiremerts when subjected 1 the guidelines of IEEE 3H-1975. to setemic testing at amplitudes greater than required. Five OPE and one SSE hiaxial random tests were performed in three mutually perperdicular axec over a t reguercy rarge at 1 to 100 ilz. Functioral pertormar ce was demonstrated betore, during, ard att er seismic excitatica. IPM Cetector A combination of test and analysis The IPM detector movement durirq a seismic evert is demonstrates qualification of the controlled by the tuel bundle and maximum excitatior detectors for their installed occurs at the natural t requency ot the bundle. The location 7e @FsT TWs Gatt<t.NSS C$: detector was tested at discrete treguencies ir the Icg,g 34y-[qqy, horizortal axes and analyzed for vertical loads. Capa bilit ies, both tested ard analyzed, exceed t he reg'3 irement s, demorstrating qualitication. Conductivity Elerrent The conductivity cell was analyrert The satety tunction of the cell is passive, however, to withstand seismic loads it must ra inta ir its structural la+nqrity. Ar a lys is significantly greater than irdicates ro resonarces in any avtt t'elow 100 H2 a-d required 7TC oEST PE (,pS6d% the ability to withstand loa 1s more t haa 15 times 05: gg 3W -j$) great er thar required. Condensing Chamber This equipment is qualified by Stress analysis it.dicaten that the cor. der air g chamter analysis to meet the HCGS seismic meets the requirement s Ot the ASt1E code ar d that the t requirement applying the ASME lowest calculated allowable momer t reactior exceeds 3 Boiler and Pressure Vessel the' paxirum momea.t of any condensta 7 chamt cr Code Sectior 111. ta s t a lla t i on. J 4 -Amendment 13

) { s HCGS FSAR TAHLE 3.11-4 MECHANICAL EOillPMENT SELECTED FOR llARSH 1/86 ENVIRONMENT OUALIFICATION PAGE 20 OF 8 3 P.O. 4 M141(O) Component: Nuclear Relief Valven. Manufacturers Crosby Valve & Gage Company I.D. No, Model No. Functional Description Location 1 FD PSV F076 Styles VR HPCI Vacuum Breaker Line Reactor Ridg. EL 077' 1 FD PSV F077 Styles VR HPCI Vacuum Breaker Line Reactor Bldg. EL 077' l 1 FC PSV F06 3 Styles VR RCIC Turbine Exhaust Valve Reactor Hldg. EL 077' 1 FC PSV F064 Styles VR RCIC Turbine Exhaust Valve Reactor Dldg. EL 077' I itF PSV 4003 Styles VR Disch. Vol. Vent'n (Va*:. Hk r. ) Reactor Hldg. El. 102' . 5 :0 2 ?. "ty "":V :-S ::' "r:1 :: "u ppF; ' ~ ~ M '; [ et 'a2' p. .. w;2a Sti'. Jr.33 "0 : V ^u t br " ;l C:: " Fel " [' "I'N - i ^ 1 An PSV 4504A JO-25-SPL

SRV PSV F013A Acc. Relief Valve Drywell Torus, Reactor Hldg.

El. 121' ) 1 AD PSV 4504H JO-25-SPL

SRV PSV F013D Acc. Relief Valve Drywell Torus, Reactor Hldg.

El. 121' 1 All PSV 4504C J o-2 5-S P L

SRV PSV F013C Acc. Relief Valve Drywell Torus, Reactor Oldg.

El. 121' 1 An PSV 45040 JO-25-SPL

SRV PSV F013D Acc. Relief Valve Drywell Torus, Reactor Hldg.

El. 121' 1 Ait PSV 4504E Jo-25-SPL

SRV PSV F013E Acc. Relief Valve Drywell Torus, Reactor bldg.

El. 121' i 1 All Psv 45041' Jo-25-SPL

SRV.PSV F013F Acc. Relief Valve Drywell Torus, Reactor tildg.

El. 121' 1 All PSV 4504G J &-2 5-S PL

SRV PSV F013G Acc. Relief Valve Drywell Torus, Reactor Bldg.

El. 121' i 1 All PSV 4504H Jo-25-SPL

SRV PSV F013H Acc. Relief Valve Drywell Torus, Reactor Bldg.

r El. 121' n Pits H/04 21-cag Amendment 14 - + nea.k.sou tsamset wment av. % unsaas vu.k zm cuar :uaac wcacao ne summm. newises uc curAcressncs.

- ~. . ~. e a ~ HCGS FSAR TAHLE 3.11-4 MECHANICAL EQUIPMENT SELECTED. FOR HARSH 1/96 ENVIRONMENT QUALIFICATION PAGE 51 OF 83 P.O. 8 P3Ollyl Components Large Valves Manufacturers Anchor Darlina Valve Co.

1. D._N_o_.

M_o_de l No_.. Functional Description Location lilHliV F003 G14 Not Applicable' Isin Closure Signal Valve Drywell Torus, Reactor Bldg. EL 077' t aialIV Fuu4 Gi4 Not Applicable Isin Closure Signal Valve Reactor Bldg. EL 077' l iti' liv FO!9 G14 Not Applicable Drywell Equip Drain Sump Pump Drywell Torus, Reactor Bldg. EL 077' litilliV FU2O G14 Not Applicable Drywell Equip Drain Sump Pump Reactor Bldg. EL 077' 16titilV 5262 Not Applicable RU/Drywell Dr To Dr Coll' Tk Reactor Bldg. EL 077' IHHilV 5275 Not Applicable RB/Drywell Dr to Waste Coll Tk Reactor Bldg. EL 077' lHC61V 5551 Not Applicable Reactor Dldg Isin Valve Unit 1 -Reactor Bldg. EL 132' & KA11V 7626 Not Applicable Reactor Bldg Isolation. Reactor Bldg. EL 077' A KHl4V 7629 Not Applicable Reactor Illdg Inolation Reactor Bldg. EL 077' i ctCe6V 340uM Not Applicable Sys IPD3-IPDll Isin Valve IV049 Reactor Bldg. EL 077' 1 Ctli HV $035 Not Applicable RB Nitrogen Sply Valve Reactor Bldg. EL 077' I t:G 66V 2 3 25il Not Applicable Core Spray Pump Rm Unit Cls Reactor Bldg. EL 054' 1 I:CV 015 2 Not Applicable - Check Valve (B"-HCC-CK) Reactor Bldg. (P610 53.1, M.R. No. 15.7) El. 054' 1 HCV 038 Not Applicable Testable Check Valve (6"-CBB-TCK) Reactor Bldg. [P61D 51-1, M.R. No. 3.9] E1. 054' M PHS 8/04 60-az kemeur W

~ 6 O 8 %- s 1 HCGS FSAR i ] TABLE 3.11-4 MECHANICAL EQUIPMENT SELECTED FOR HARSH 1/tf 6 ENVIRDNMENT OUALIFICATION PAGE 53 OF 83 P.O. # 113 U I,( V1 Component: Mrgo Valves Manufacturers Anchor Darling Valvo Co. 1.D. No. Model No. Functional Description [ Misc. Datal Location 1 Al'V 0's 5 Not Applicable Tostable Check Valve (4*-GDB-TCK) Reactor Bldg. lP61D 51-1, M.R. No. 3.3] El. 102' I APV 057 Not Applicable Tentable Check Valve (4"-GBB-TCK) Reactor Bldg. (P61D 51-1, M.R. No. 3.31 El. 102' l APV 056 Not Applicable Testable Check Valve (4*-CBB-TCK) Reactor Bldg. [P&lD 51-1, M.R. No. 3.31 El. 102' 1 4 HCV 024 Not Applicable Testable Check Valve (4"-GBB-TCK) Reactor Bldg. [P&lD 51-1, M.R. No. 3.3] El. 054' 1 HCV U10 Not Applicable Testible Check Valve (4"-GBB-TCK) Reactor Bldg. lP61D 51-1, M.R. No. 3.3) El. 054' I I HCV 033 Not Applicable Testable Check Valve (4"-GBB-TCK) Reactor Bldg. IP&lp 51-1, M.R. No. 3.31 El. 054' I HCV 127 .Not Applicable Te9 table Check Valve (4"-GBB-TCK) Reactor Bldg. (PhlO 51-1, M.R. No. 3.3] El. 054' I j i HCV 130 Not Applicable Testable Check Valve (4"-CBB-TCK) Reactor Bldg. [P61D 51-1, M.R. No. 3.3) El. 102' 4 & HCV l t: 3 Not Applicable Tentable Check Valve (4"-GBB-TCK) Reactor Bldg. ( P61D 51-1, M.R. No. 3.3] El. 102' 4 1 APV 039 Not Applicable Tentable Check Valve (3"-GHB-TCK) Reactor Bldg. i ( PsID 52-1, M.R. No. 3.1) El. 102' I j l APV u40 Not Applicable Testable Check Valve (3"-GBB-TCK) Reactor Bldg. [P61D 52-1, M.R. No. 3.11 El. 102' 1 1 APV Obu Not Applicable Tentable Check Valve (3"-GBD-TCK) Reactor Bldg. (P61D 52-1, M.R. No. 3.1) El. 102' ! APV u61 Not Applicable Testable Check Valve (3"-GBB-TCK) Reactor Bldg. (PsID 52-1, M.R. No. 3.1) El. 102' 1 HEV uJu Not Applicable Testable Check Valve (3"-GBB-TCK) Reactor Bldg. [ P61D 52-1, M.R. No. 3.1)

81. 054' i

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'h g' Q) IICGS FSAR TARLE 3.Il-4 MECHANICAL EOHIPMENT SELECTED FOR HARSH 1/86 ENVIRONMENT QUALIFICATION PAGE 72 OF 83 l'. O. I l' 3 0 3 A ( 0) Component: Small Valves Manufacturers Rockwell International 3.D. No. Model No. Functional Description (Misc. Detal Location .) I tiCV 069 H 3 tl YTl Check Valve'(l"-EHA-CK) Reactor Bldg.' (P&ID 51-1, M.R.-No. 9.11 El. 057' 1 ItCV 090 H3HYTl Check Valve (l"-EBA-CK) Reactor Bldg. j [ P& I D 51-1, M.R.-No. 9. l l El. 057' 1 ItCV 194 H3HYTl Check Valve (l"-EHA-CK) Reactor Bldg. i (P&ID 51-1, M.R.-No. 9.11 El. 056' IHC liv 5055A' 3624-MT Valve from RilR HX to liydrogen Recombiner Rector Ridg. EL 058' 1 i 4 linC HV 5055H 3624-MT Valve from RHR llX to Hydrogen Recombiner Reactor Bldg. l EL 090' ,1 IGS IIV 5057A 3624-MT Valve from RHR HX to Hydrogen Recombiner Reactor Ridg. 3 I EL 058' l l IGs ilV 505765 3624-MT Valve from RiiR HX to Hydrogen Recombiner Reactor Bldg. 1 EL 090' I liCV 308 83HYTl Check Valve (2"-ERA-CK) Reactor Hldg. IP&ID 52-1, M.R. Item No. 9.5] El. 056' 1 liCV 309 838YT1 Check Valve (2"-EDA-CK) Reactor Bldg. IP&ID 52-1, M.R. Item No. 9.5) El. 056' 1 HCV 312 838YT1 Check. Valve (2"-EBA-CK) Reactor Bldg. I P& I D 52-1, M.R. Item No. 9.5) El. 0 56' 4 ~ l HCV 313 83HYT! Check Valve (2"-EDA-CK) Reactor Bldg. L IP&ID 52-1, M.R. Item No. 9.5] El. 056' I stCV 423 838YTl Check Valve (2"-EDA-CK) Reactor Bldg. [P&ID 10-1, M.R. Item No. 9.5) El. 108' 1 -.-,s I.

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s I a HCGS FSAR t/86 TADLE 3.11-6 Pagn I of 3 J SAFETY REL ATED EQUIPMENT LOCAlfD IN A HARSH ENVIROPNENT Exf MPTED FROM ENVIRONMENTAL QUALIFICATION REQUIREMENTS E0ulfHfNT TAG NO. MPL NO. DESCRIPTION REASON 1 AVE 761 Electric Duct Heater, SLC Due to reactor building tamparature Incranse during e De A,,the duct hanters will

Hvf 761 E l ec t ric Ouc t Has ter, SLC not function due to the temperature control settings, unich is telow 00A tullding[

10 vt 759 Electric Duct Hanter. RCen temperatura. The heater circults are protected by pr] mary and backup $1FC--

_ 2.

10 WE ?60' Electric Duct Hester. It'CI Mg lN N6l i } t AN 205 4.16 KV Brankar RRS Pump mtor the RRS pump mtor breakers trip upon recalpt of a LOCA signal shuttinq down the 4 4 i Dr4 10% 4.16 kV Praskar RRS Pump m tor pump. The breakers are no longer required to perform a safety-ralated f unct ion. I (N 205 4.36 KV Dresker RR$ Pump mtor i ON 205 4.16 RV Dresker - RRS Pump Motor 10 Y 701 Panel these panels and transformers are located in the reactor building and fead non. 10 Y 702 Panni critical class IE loy s. ~ They are protected by primary and backup IE trackers. ) 10 Y 705 Panal ] 10 Y 704 Panel 10 x ?Of Trnnsformar 10 x 707 Transformer 3 10 x 203 Tr an s former 3 10 x 20s Tr an s f ormer i a ) 1.sr.T(.Nol6 Tamparatura Elemants These tamparature elements nra not quellflod for sutenrq*nce caused by a feadwater 1 5r-It-N017A Tamparatura Elements line break In the stens tunnel. Thay hava teen prowlded with primary and backup 1.M.T E.N01.'C Temperature Elements IE bus protective devices located in the hazard frea area. I.57.fE.h010A Temperature Elaments q l.5K. f f-Na l Olt Tamparature Elements I-W.TE.N0100 Tarnparature Elements 'l.SK.TE.N0100 Tamparatura Elements j l.$k.T E.N O I ?lt Tamperaturo E1ements f 1-SK-TE.N0120 Temperature Elamants Amendment 14 ) ) 4 I

HCGS f SM i/86 1ADtf 3.11-6 Paqa 7 of 3 SAFETY-RFLATED IQUlfHfNT LOCAlf0 IN A HAasil [NVIRONW NI ENEMPffD FROM ENVIROP#4f NT AL QUAL IFICATION RfQUIRf Mf NTS 1 enlPHI N T TAG *(). MPL NO. DESCn i f'T ION REASON - ~ ~ - - - - ~. - - ~ ~ ~ -

--=

1 41-Hy-Foto Hitor Operatad Valvas Thasa mitor oparated valvas% ara not quellflad for sula.rqanca

1. A;1-Hv-F 0 7 l

%) tor Operstad Yalvas caused t:y a fandwater line tra.sk in the stasm tunnal. They havn taan prov itta,f wit h l =P-hy-%8794,H Mitor Opara ted Valves pr imary and t:ackup IE tus protect iva davicas locatad in tha barard f r aa area. 1 =P.hy-anitA,0 Motor Opera ted Valvas 1-m-ny-m sa,n Motor operated e lv s lAND SotsjotD VAlV65{ 1 *P-nv-say.A,8 K3 tor Oparatml - 6 1->.P.Hv.sa 5 7 4 fi Hitor Oparated $" a ~ ~ ~g t L1 h - r i y 9g b._- n_____._. t cc, L,. _, _ _. m \\. m. m____. Na T ag Pn. Cll-FOIO Position Swltch Thase NAPC0 limit sw itches per f orm no sa f et y functions. Fallura mdes and ef fec t e-. l eq en. Cll-foll Position 5=ltch analysis has shown that there are no possibla f a il ura maas whle h can adversal y P. s T ag Ni, C ll-F IN Position Switch effect the IE power supply. No Tag Pa. Cll-Fl81 Position 5=lich I-p r -SV-F CO/. A E71 Solanold Yalve Thesa solanoid valvas and posi t ion swi tchos par f orm no saf ety functions, n>= var, tai Tao 47 E71-f006A Position Switch tocausa of their association with e IE powar supply, thay have taan providad with 1 -Of-5v-f otv.D E71 Solenoid Valve primary and tackup protective devices. Pn laq Pn. [ 71-f 00Ni Position Switch 1.HC-SV-f04fA Eli Solanoid Valva Mi Tarh. Fil-F041A Position Switch I-tic-S V - T 0 410 fil Solanoid Yelva P. i raq us, f i l-F0418 Ibs i t ion s Itch 1 tte-Sv-f 041C Ell Solanoid Valva No Ing k2 Ell-F04tC (bsition Sul tch Amand**nt 14 d 1 - AE - W-41% N %7sb (/Ad

t IiOM I ' Mt 1/8(3 TARLF 4.ll.6 paga 3 of 5 S ArETY.REL ATED f tJOll'HE NT LOCATIO IN A HAHSH ENVlH04 MINI EX1MPilD FRCH ENylRUPNENT AL QUAllf lCAfilN REQUIRIMENIS i e.iti% n r 1N r4). MPL to. DEscalPTICH REASON i.or.',V.l o419 ril %I ano i d yniva Ihasa solanoid val ves and : is t ilon su l t r hos por f or m rio so t o t y functions, f, i n q P.o. , E l l-f 0410 I'osition ',w l t c h Itivavar, t or ausa of their assnclation with n I f povor supply, they havn 1.pt:.' y f o,o A f Il Solanold vniva baan proviriod with primary and backup prot ec t iva davices, e to T,s q te. Ft1.f050A posttlon Switch

1. i :. '.v. t v,N Eli Solanold velva ho T a q t.o.

i E l l-f 0500 l'ost tlon Sultch 1 4CIC Ync Pump Hitor $peca Hantar They are protected by primary and t nckup t r t ronhe.r s.

j. -

./t. i J. RCIC Gland Sant Cond. Motor Space pantar I. f c.T '.u.1.' I t , Tep. Switch High Provida alarm f unction only. Determinad t y analys t s that no twi t condition (gr ounit, l. i r. ! '.H. 41 t n Tamp. Switch High open or short circult) can impact the I?SV de Se f at y rei nt a.t gewar tus. 1 6t'.t',H.elnd Laval 5=. High m Nota: All of the equipmant in this tahin is gun a l t ic.1 for its fuartlon in in accordanca ulth IUCfH50.49 requiramant s, i.fC.Hv.4161 ! Motor Operated Velve T h i s (8C I C s y s t em Pn t or opern t ad va l v a par f or ms no sat a'y function, it>=avar, trveo sis c( lts assew:lat ion with a Class IE powar supply, it hes t.. n proviend.I t h Clas s 10 pelaarj and techup protect ive davicas. 10-P-JiH 50 "te.a

CCI Auw. Oil Pu=p Motre Space Hanter They era protactad by primary and techup li tir ao ce.

n o-r. I l u ',p. Her.) ts'Cl Gland Seal Cond. Motor Space omster 10-r-166t9. Htr.) ,1('Cl vne. Pu=p Ntor Spaca Hooter Amend-nn1 64

HCGS FSAR Drive water pump - The drive water pump pressurizes the a. system with water from the condensate treatment system and/or the condensate storage tank (CST). One spare pump is provided for standby. A discharge check valve prevents backflow through the standby pump. A portion of the pump discharge flow is diverted through a minimum flow bypass line to the CST. This flow is controlled by an orifice and is sufficient to prevent pump damage if the pump discharge is inadvertently closed. Condensate water is processed by two sets of filters in the system. The pump suction filters are disposable-5c element type with a -micron absolute rating. A 250-micron strainer 's provided at the inlet of each suction filter to reduce the debris loading on the suction filter elements. A 250-micron strainer in the suction filter bypass line protects the pump when both suction filters are out of service. The drive water filters downstream of the pump are cleanable-element type with a 50-micron absolute rating. A 250-micron strainer in each drive water filter discharge line protects the hydraulic system if there is a filter element failure. Local differential pressure indicators and main control room alarms monitor the filter elements as they collect foreign material. b. Accumulator charging pressure - Accumulator charging pressure is established by precharging the nitrogen accumulator to a precisely controlled pressure at a known temperature. During a scram, the scram inlet and outlet valves open and permit the stored energy in the accumulators to discharge into the drives. The resulting pressure decrease in the charging water header allows the CRD drive water pump to run out, i.e., allows the flow rate to increase substantially, into the CRDs via the charging water header. The flow element upstream of the. accumulator charging header senses the high flow and provides a signal to the manual / auto flow-control station, which in turn closes the system flow-control valve. This action maintains increased flow through the charging water header, while avoiding prolonged pump operation at run-out conditions. Pressure in the charging header is monitored with a c local pressure indicator and a main control room high pressure alarm. w 4.6-11 l

HCGS FSAR 01/86-s- ( requires one to be out of the main control room. Administrative control minimizes subsequent checks. i. Verify-that water is available in the CST.- .j. Verify that oil is available in RCIC turbine oil reservoir and that the turbine and pump are ready to run as defined by the technical manuals for the turbine and pump. k. During extended periods of operation and when'the normal water level is again reached, the HPCI system may be manually tripped, and the RCIC system flow controller may be adjusted and switched to manual operation. This prevents unnecessary cycling of the two systems. Should automatic shutdown of_the RCIC system occur due to high water level in the RPV, the system will automatically restart on recurrence of low water level. Trips of the RCIC system due to other ~ r conditions must be operator-controlled. If the RCIC flow is inadequate, HPCI flow is initiated automatically by a low water level signal. 1. Adjust the flow controller setpoint as required to maintain desired reactor water-level. m. When RCIC operation is no longer required, manually trip the RCIC system and turn the flow controller back to automatic. n. Close the turbine steam supply valve, E51-HV-F045 and reset the flow setpoint. 1: ~ o. Reset the turbine trip throttle valve. p. Stop the barometric condenser vacuum pump. q. Close the cooling water supply valve E51-HV-F046. -[Esl-W-RrJyi Verify that valves'45WUFM58, E51-HV-F025, and r~- r. E51-HV-F026 reopen automatically after valve t 5.4-38 Amendment 14 -,. ___, _ J... \\

HCGS FSAR V [ECl-LV-Fbos] E51-HV-F045 is closed. Valve 7;;

r/ TCC opens as required by signal from barometric condenser.

s. Verify that the system is in the standby configuration as shown on Figures 5.4-8 and 5.4.-9. 5.4.6.2.5.2 Test Loop Operation This operating mode is manually initiated by the operator. Operator action is required as defined below: a. Complete the verification made in steps a. through j. of Section 5.4.6.2.5.1. b. Position all motor-operated valves as shown on Figures 5.4-8.and 5.4-9. c. Open E51-FV-F059 and E51-HV-F022 fully. ( d. Start the barometric condenser vacuum pump. e. Open E51-HV-F046. f. Open E51-HV-F045. g. Verify that valves E51-HV-F004, E51-LV-F005, E51-HV-F025, and E51-HV-F026 are automatically closed after valve E57-HV-F045 is opened. h. Adjust E51-HV-F022 to obtain a pump discharge pressure of 300 psig. i. Observe turbine rpm on speed indicator. j. Turn the remote-manual switch for E51-HV-F019 to the open position, and release. Observe that valve E51-HV-F019 cycles are fully open and closed by [ watching position lights. Also observe the turbine 5.4-39

m n l HCGS FSAR 1/86 l TABLE 5.4-2 RHR SYSTEM RELIEF VALVE DATA Setpoint capacity Method of Valve Location Valve psig__ _qnmtt8 . Collection (3) Shutdown cooling suction line PSV-F029 E240 10 DRW l (outside containment) / }EEE@ilo Pump suction line PSV-F030 A,B,CSD 10 DRW g Heat exchanger inlet line(*3 PSV-F055 A,B 7 "- ???.re: 1 E'- ^:: r---:--- l P Heat exchanger outlet line to Rcic(*3 PSV-F097 i'" '"^ Pump discharge line PSV-F025 A,B,C,D 410 10 Suppression pooi l Heat exchanger (shell side)(8 ) PSV-4431 A,B 410 Thermal relief Suppression pool 125?O Therral relief valve on shutdown PSV-4 4 2 5 GPRRR 0.1 DRW cooling suction line (inside ed cortairment) P' Heat exchanger vent vacuum breaker (9) PSV-151 A,B ELO.' esid -'2--:- c. _- ir-r. PSV-15 2 A,3 (t) Capacity is based on setroint plus 10% accumulation. (a) _GE-supplie1 valves, gue (*)

-= -

: en ::: trer rei:^

nr DRW = dirty radwaste collection.

(*) Deactivated as a consequence of 'RHR st?am condensing mode elimination. l l 4 Amendmart 14 1

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l 2 FIGURE 5.4 2 SHEET 1 OF 2 Amendment 14,01/86

HCGS FSAR 01/86 The MSIV sealing system is divided into two independent subsystems. The inboard subsystem maintains a seal between the two-MSIVs, and the redundant outboard subsystem maintains a seal between the outboard MSIV and the MSSV. Sealing is accomplished by maintaining a higher pressure in the main steam lines than in the containment. The operation of the MSIV sealing system is discussed in Section 6.7. A main steam drain line connects to the main steam lines between the two MSIVs on each main steam line outside of the primary containment. Isolation of this line is provided by the inboard MSIV and by a motor-operated globe valve in the drain line that automatically closes upon receipt of a containment _ isolation signal. 6.2.4.3.1.2 Feedwater Lines The portion of the feedwater system that forms part of the RCPB JEE-GNEWHag and penetrates the primary containment has threetvalvest. The UME _ggfpat first valve, a check valve, is classified as a containment isolation valve and located inside the primary containment. The second valve, a positive-acting check valve, is classified as a (~ containment isolation valve and located outside the primary containment as close as possible to the primary containment penetration. Upon a loss of water flow into the RPV, these valves close as normal check valves, and, in addition, the main control room operator can assist in starting the outboard valve closure by sending a signal.to open arranged in parallel, releasing air p$wo fail-open solenoid valves ressure from the operator cylinder. If a break occurs in the feedwater line, the two containment isolation valves prevent significant loss of inventory and offer immediate isolation. During the postulated LOCA, it is desirable to maintain reactor coolant makeup from all sources of supply. For this reason, the feedwater containment isolhtion valves do not automatically close on a primary containment isolation signal. A third valve in the feedwater line is a motor-operated check valve located outside primary containmentpand is capable of being remotely closed from the main control room. This valve provides redundant isolation and long-term leakage protection upon operator judgment that continued makeup through the feedwater line is unavailable. I3 CLASSIPIED A ~ CourAIMLir (DOL /Tn) Vue 6.2-45 Amendment 14 t

HCGS FSAR 01/86 After observing indication of low feedwater flow, the operator may close the third valve within 20 minutes after a postulated LOCA. YGWAIA1HBJT 131ATkWI In addition to the third valve, there' areIvalves on the high l pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) discharge lines, and on the reactor water cleanup system (RWCU) return lines that connect to the feedwater lines i IN between thetoutside containment isolation valves.hne the th:rc ( W Those valves can be closed by operator action from the main control room f See Section 5.4.9 for a further discussion of the design of the main steam lines and the feedwater lines. 6.2.4.3.1.3 Residual Heat Removal Shutdown Cooling Suction Line The residual heat removal (RHR) shutdown cooling suction line penetrates primary containment and taps into one of the two recirculation loops. Isolation is provided by two normally closed motor-operated gate valves that are interlocked closed by ( a reactor high pressure signal during normal operation and are maintained closed during an accident by a low water level isolation signal. One containment isolation valve is located inside primary containment, and the second valve is located outside primary containment. A2DrrMALLY, *w HR~C MDlw FCIC VAulGS cAo bG CRaseb Son THE MAIN COJIPa. Ettd1 To Wet /its A WATER SEAL. CO T@ THIRD L/ALAG 90 ADDITicM To StrPALWMC, wATEP To Tw ~P V. S s t Secrvis 6.D.B.2.3 m?. cue 7HER DETAILS. h .f( 6.2-46 Amendment 14 l l

HCGS FSAR' 01/86 c 6.2.4.3.1.8 Reactor Pressure Vessel Headspray Line The RPV headspray line is used during the shutdown cooling mode to limit thermal stresses in the reactor head volume. Isolation for this line is provided by a normally closed, motor-operated gate valve inside containment and a normally closed, motor-operated globe valve on the outside. Both valves are interlocked closed by a reactor high pressure signal during normal operation and are maintained closed during an accident by a low water level isolation signal. 6.2.4.3.1.9 Main Steam Drain Line The main steam drain line is isolated by two motor-operated gate valves that isolate upon a containment isolation signal. 6.2.4.3.1.10 Reactor Recirculation System Process Sample Lines ( OneP' The reactor recirculation system 7 process sample lines are isolated by two, normally4: :: 0, solenoid-operated globe valves that isolate on a containment isolation signal. 6.2.4.3.1.11 Standby Liquid Control Line Provided that the standby liquid control (SLC) system has not been used, the explosive-actuated valves provide the absolute seal for long-term leakage control. After system operation, isolation is provided by a check valve inside primary containment, and two, independent, motor-operated globe stop-check valves located outside primary containment on branching lines. The stop-check valves are manually closed from the main control room after system operation. 6.2.4.3.1.12 Reactor' Recirculation Pump Seal Lines The reactor recirculation pump seal lines are isolated by a check valve inside primary containment and a motor-operated globe valve outside primary containment that closes on a containment isolation signal. j 6.2-48 Amendment 14 ,_.u,,, - - - - - - -. _ _. _ _ _, _, - - - -. - ~ - -. _, - -. __--__.._.,,.m. ______-_,-_y

A i i HCGS FSAR 9/85 the containment. Table 6.2-25 identifies those penetrations isolated with only a single isolation valve. Figures 6.2-45, 6.2-46, 6.2-47, and 6.2-48 show the limits of the extended containment boundary. 'All manual valves at the system boundary, f vent valves, test valves, and drain valves, arellec%;d cl;; d ndi under administrative control to assure the integrity of the extended containment boundary. Isolation provisions for the extended containment boundaries are identified in Table 6.2-26. Table 6.2-26 also evaluates the ability of check valves and safety / relief valves to maintain the extended containment boundary. All extended containment boundaries are Quality Group B (i.e., ASME B&PV Code Class 2 piping), Seismic l Category I, and designed to temperature and pressure ratings at least equal to that of the containment as identified in Figures 6.2-45 through 6.2-48. Missile protection for plant systems and structures is discussed in Section 3.5. 6.2.4.3.5.1 Conclusion on Other Defined Bases When greater safety is ensured by using a single primary 4 containment isolation valve, a dependable closed system outside primary containment is provided to act as a second barrier against the release of radioactive materials. i i i ( 6.2-62 Amendment 12 i

HCGS FSAR 01/86 i instrumentation, and those lines containing excess flow check valves, will have their leak tightness verified during the Type A test. These instrument lines were designed on an "other defined basis" of GDC 56 (see Sections 6.2.4.3.2.21 and 6.2.4.3.5) and hence are not capable of being Type C tested. Instrument lines are provided with a manual isolation valve outside containment for greater reliability. The systems they serve are closed systems outside containment, thereby providing reliable boundaries against containment leakage. The Type A test that will be conducted on these instrument lines serves to adequately assure integrity. 6.2.4.4.3 Feedwater Isolation Valves MC l p f ..._w o. _m,._. .._,3. ~... _ ,, n c e.n e, e. oge m. 21

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1 HCGS'FSAR 01/86 15 leakage cf radicact:ve contaminants-through the i cel at-ica valves-1 Eduring approximately a 1-hour period after the accident, 1.c., yentil the uater ceal ic recctablichedr-thuc, nc bypacc leakage Of c-t-he-4eedwa t e r cyc t er ic expected to-occur-Y 9 A Typ; C water test will be perfor. ed at 1.10Pa on the outermast-O checP valve and itt leakage included 'ith ill ether Gruydrostatically tected valvec. Once the eater ceal cycter is 9 activated, any external Icakage would be threugh thic beundary 9unlea via tha san 1 fluid The Type C Mater tect vill br 7 suf ficient te assur-e-pr-oper Icakage verification. Also sc;

Sect: enc

'.4.0, 0.2.2.2.2, and 0.2.4.2.1.2. 6.2.4.4.4 Main Steam Isolation Valves l 10CFR50, Appendix J, Paragraph III.C.2(b) requires valves that are sealed with fluid from a system to be pressurized with that fluid to a test pressure not less than 1.10Pa. The main steam isolation valves (MSIVs) will be leakrate tested by pressurizing between the inboard and outboard MSIVs and between the outboard MSIV and the main steam stop valve (MSSV) at a reduced pressure of 5 psig. The main steam isolation valve sealing system (MSIVSS) (see Section 6.7) is initiated manually approximately 20 minutes after the onset of a LOCA and only after main steam line pressure is below 20 psig. This latter restriction is necessary since the MSIVSS maintains the pressure between the valves at reactor vessel pressure plus 5 psig and because a back pressure i differential of 25 psi will lift the MSIV disk, unseating the valve. Therefore, testing of the two MSIVs simultaneously, 4 between the valves, at 1.10Pa would lift the disk at the inboard valve and result in a meaningless test. A test will be conducted at 5 psig (the seal system differential pressure) with the total i observed leakage through both the outboard MSIV and the MSSV conservatively assigned to that penetration and, limited to 11.5 scf per hour for any one main steam line. 4 i 6.2.4.4.5 Containment Air Locks l ) 10CFR50, Appendix J, Paragraph III.D.2(b)(ii) requires air locks that have been used during periods when containment integrity is i not required by the plant's Technical Specifications to be tested at the end of such periods at not less than Pa. In addition to the 6-month intervals, air locks will be subjected to an overall air lock leakage integrity test only when maintenance on the air lock has been performed that could affect the air lock's sealing capability. This is an exemption to Paragraph III.D.2(b)(ii) i t i 6.2-62c Amendment 14 ,,_._.,c

HCGS FSAR 8/84 All valves that are exposed to the primary containment atmosphere after a DBA are tested with air or nitrogen at primary containment peak accident pressure, P, as defined in a Table 6.2-22. All valves in lines designed to be filled with a liquid for a minimum of 30 days after a DBA are leakage-rate-tested with the same liquid at a minimum pressure of P l a-Liquid leakage is not converted to equivalent air leakage, or added to the Type C testing total, but is reported separately as " liquid leakage" and included in the Technical Specifications. All the valves tested with liquid are identified in Table 6.2-24. hNSER[ The Total Allowable Leakage acceptance criteria for penetrations and isolation valves subject to Type B and C tests are given in Chapter 16. 6.2.6.4 Schedulino and Reocrtino of Periodic Tests The periodic leakage rate test schedules for Type A, B, and C testing are given in Chapter 16. Type B and C tests are performed prior to initial criticality and periodically thereafter, during shutdown periods or normal plant operations. The preoperational Type A test follows.the preoperational ASME Section III pressure test. A primary containment isolation system functional test and Type B and C leakage tests are completed prior to the preoperational Type A test. The procedure for reporting test results is given in Chapter 16. 6.2-94 Amendment 7

INSERT FOR PAGE 6.2-94 1 ~ Containment-isolation of.the feedwater lines represents a unique situation which requires a combination of air and water' testing and therefore merits further discussion. During the short-term feedwater system line-up, isolation of the feedwater lines is provided by -valves AE-V002, AE-V003, AE-V006 and AE-V007 and the water seal upstream of i the third feedwater heaters (see Section 6.2.3.2.3).

Hence, a Type C test will be performed on these valves with their leakage appropriately included in the 0.60 La criteria.

i During the long-term feedwater system line-up, isolation j of the feedwater lines is provided by a water seal on the j third feedwater check valves, AE-V001, and AE-V005. Identifi-cation of these valves as containment isolation valves-requires a similar classification for the first valve in each branch line between the second and third feedwater j check valves, BD-V005, BJ-V059, and AE-V021. Since the leakage past these valves will be into the RCIC, HPCI and RWCU systems, respectively, which are seismically qualified, i water-filled, closed systems outside containment, there is no requirement to identify their specific leakage in the Technical Specifications. However, leakage through 2 the valves which form the long-term seal boundary of the feedwater lines (i.e., AE-V001, AE-V005, AE-V021, BD-V005 and BJ-V059) will be determined by a Type C water test and will be limited to 10 gpm as specified in the Technical i Specifications. Since these valves are sealed with water, the leakage determined from their Type C test need not be included in the 0.60 La criteria per 10CFR50 Appendix J Paragraph III.C.3. i 2 I i i i t i i v_,, -., _ _ - - -. _.. _ - _,. - - _.,. - -,, - ...-.,.,__,,...m_.. ,...,_...._..-,,_c--.4

TA8tt 6 E CONTA!k'4ENT PEh Valve krLe-Cce.t a i s-en t hRC General ancre-Valve Fe6etratic-Line Lire Desig* E5F 0-ifice Valve talve Arrangement (2) Tpe C N,:- !sciate: Flute 5 ire, tn. Criterien Syste-fill Plate Twe(l) location FLID(F1 Test P30:E!5 LIAE FE%ETE ATIONS P-1; Ma n Steam Stea+/ 26 55 AB-V028 G8 Inside 1/A ho h at e* 26 A8-V032 G8 Outside ho 2 A8-V059 GB Outside ho 2 KP-YO10 GE Outside ho P-le Matn 5 tea

5 tea +/

2E 55 ho A8-V029 GB Instae 1/A M Wate-26 AB-V033 GB Outsice M 2 A8.VD60 G5 Outsice ho 2 KP-V009 G5 Outstce ho r... Main Stea* Stea+' 26 $5 ha A3-V030 GE Instoe 1/A As hater 26 AS-YO34 G5 Outsice ho 2 AB-V061 GS Outsice h ? kP-V006 GS Outsice ho P-10 Main Stes* 5 tea +/ 26 55 ho AS V031 GF Instee 1/A ho hater 2t AB-V035 GE Outssce ho 2 A8-V062 G5 Outsice M 2 kP-V007 GE Outsice ho 5-Feec=ater heter - 24 55 ho Al V003 CK Insice 2/8 Tes ?4 AI-V002 CK Outstce Yes 6-es tecc.ater -ate- ' 24 55 ha AE-V007 CA Insice 2/8 Yes s 74 Al V006 CK Outstce tes P-3 Pa4 5nutdo a Water 20 55 Yes BC-V071 GT Instoe 3/C Yes Coolic: Suc t ion 1 BC PSV-4425 P5V Inside Yes 20 BC-V164 GT Outside Yes P-4. E=2 Shutoo a Wat er 12 55 Yes BC-V014 CK Inside 4/D Ten Cooling Peturn 1 80-V118 GB Instoe Yes 12 BC-V013 GE Outstee tes P-46 kaa Snutfo=n heter - 12 55 Yes 80-Vll! CK Inside 4/D fes Cooling Eetu r 1 80-Vll7 GB Instoe Yes e 12 80-V110 GB Outstde tes T1002775 H A=-\\e2J Cn craw 'p5S fzi 6 BD-Ws 67 otEsas yE5#3 24 /E-61 CX otaate 4 /E-LO24 Ch CW.>lCG YGS ' 8 BJ-tcS1 sr CW,alD6 W3 ' J4 As-g%c o< Cunlite

TAgur 6.a-6 til0NS Page 1 of J.- mgth of D froR .Ponte mt. to Primary Secondary' hormal Snutoown Post. Failure Cont ainment. valve itside Mode of Method of talve talve Accicent valve Isolatton Closure Fowe-ilves ft. Operat toa( 3) Actuat ion (12 ) Posit ion { 41 Positionfl0i Position (9) Pnsttten 5 tonal (5) T we. 5 Sourceler memaras:/t l Instr. gas Manua! O C C C 8.0.t.F.6,K = a.t y.cc 3.8 Comer. air Manual O C C C 8.0 E.F.G.t 5 2 a.t.y.cc 9.4 AC motor Manual O C C A5 15 8.0.E.F.G.k 45 U t.y.cc 16.5 AC motor Manual C 0 C A5 15 A.tt. ! 45 C t a.y.cc Instr. gas Manual 0 C C C 8.0.E.F.G.s. 5 m a.t y.cc 3.8 Compr. atr Manua! O C C C 8.D.E.F,G.k 5 2 a.t.y.c c 9.4 AC motor Manual .0 C C A5 15 8.D.E.F.G.h 45 0 t.y,cc 14.1 AC motor Manual C 0 C A5 15 A.M.! 45 C t.a.y,cc Instr. gas Manual C C C C 8.0.t.F.G.k 5 m a.t y.cc 3.8 Compr. air Manual C C C C 8.0.t.F.G.s 5 2 a.t.y.c c 9.4 AC motor Manual C C C A5 15 8,0.t.F.G.k 45 L t.y.cc 16.4 AC motor Manual C C C A5 li A.M.I 4t L t a.y.cc Instr. gas Manual C C C C 8.0.1.F.b A 5 m a.t.y.cc 3.8 C epr. air Manual C C C C 8.D t.f.b.h 5 2 a.t,y.cc 9.4 AC motor Manual 0 C C A5 15 8.0 E.F.b.a 4S b t y.cc 14.9 AC motor Manual C 0 C A5 15 A.M.I 45 0 t a y.cc hone O C C h1 h4 h. S 4.5 Flo. Manual (17) O C C C hone h4 h 5-O.5 Flo. hane O C C hi hA h4 s ' 4.5 Flo. Manual (17) O C C C hone hA h 5 4 AC motor Manual C 0 C A5 15 J 45 A D.s l Spring bone C C C h4 h4 ha s.: 0.5 AC rotor wanual C 0 C As 15 J 4$ D o.s I Flow hone (16) C 0 C h4 hA 4A s = = Sortng Manual C C C C none ha e t l 0.0 AC motor Manual C 0 C A5 15 J 45 L 6 I Flow hone (16) C 0 C ha ha h. s Spring Manual C C C C hone hA A 1 l 0.0 AC Motor Manual C 0 C A5 15 J 45 b s I w non nt lo. Ulles 3sto Rcw HAupl(6 o C C C Neu5 NA D t n 33.3 bc m MANUAL C C c A5 IS No4E NA T3 5 40.12. FtcW HANuAL(te o C C C NM3 NA B 5 34 0 Mcd hwuAL68 o C C C %E NA D t C o A5 G Nc6 NA A s St.S DC HoTR HMuAL HANDALh3) C o C C C NC46 NA A s 401 Flcw

R:R leJR24MrmJ cMLY TAELE 6. CONTA!h=I%f PCL. Valve kr.0er Contatnment NRC General and/or Valve Penetration Line Line Design ESF Ortftce Valve valve Arrangement (2) Type C h eree Isolated Flute Stre, in. Criterton System (11) Plate fyre(1) loc at ion P&f0(8) Test P-11 RCIC furbine sten 4 55 No FC-V001 GT Inside 6/1 Yes Steam Supply 4 FC-V002 GT Outside Yes 1 FC-V048 G8 Inside Yes P-12 P'ain Steam steam / 3 55 ho A8 V039 GT Inside 9/J Yes Dratn kater 3 A8-V040 GT Outside Yes P-13 Scare P-la hot used P-15 Space P-16 5 pare P-17 Reactor Rectre heter 3/4 55 No 88-SV 4310 G8 Instde 10/K Yes hatee Sample 3/4 88-5V 4311 68 Outside Yes P-la Staasoy sodium pen-1 1/2 55 Yes 8H-V029 Cx Inside 11/L Yes Ltaato taborated 1 1/2 BH-V028 $CK Outside Yes Conteel solutton 1 1/2 BH-V054 SCK Outside Yes P-19 Rectrc P ep hater 3/4 55 No 88-V043 CA Inside 12/4 Yes Seal sater 3/4 BF-vo98 G8 Outside P-25 4ecirc Pep heter 3/4 55 ho 88-V047 CK Inside 12/K Yes Seal Water 3/4 BF-V099 G8 Outside P-21 15! Access Penetration P-22 Drywell Purge Gas 26 56 Yes GS-V009 er Outside 13/M Ves Inlet Vent 6 GS-V023 BF Outside Yes 26 G5-V021 8F Dutside Yes 24 GS-V020 BF Outside Yes 4 G5 V004 GT Outside Yes 4 GS-V005 GT Outside Yes P 23 Drywell Pur9e Gas 26 56 Yes GS V024 BF Outside 14/M Yes Outlet Weat 26 GS V026 8F Outside Yes 2 G5-v025 G8 Outstde Yes a GS-V002 GT Outside Yes 4 G5-V003 GT Outside Yes P-24A Pa# Contain. Water 16 56 Yes 8C-V019 Gt Outside 15/D Yes ment Spray 16 80-V018 GT Outside Yes fl002115-Clv f L

ATICNS T4EE 6 2-16 Page 3 of 33 ength of ipe f ror" Power ont. to Primary Secondary hormal Shutdown Post-Failure Cont a treent Valve

tsid

Mode of Method of Valve Valve Accident Valve Isolation Closure Power rives, ft. Operatton(3) Actuation (12) Position (4) Position (10) Pesition(g) Position Signal (5) Time, 5 Source (6) Remares(1) l AC motor Manual O C 0 A1 15 None M 0 c,s 1.0 AC motor Manual O C 0 AS 15 n:.e u 8 a,s AC motor Manual C C C A5 15 Mone hA 0 d,t AC motor Manual O C C A5 IS 8,0,E F,G,K 30 A t 0.5 AC motor Manual O C C A5 15 8,0 E.F.6,K 30 0 t a m Spring Man al O C C C A,8 15 A t i u 12.2 Spring Manual O C C C A,a 15 0 t i Flow hone C C C h4 12.6 Flow hA hA 5 Man al (13) 0 0 0 C hone hA A s u 10.6 Flow Manual (13) 0 0 0 C Mone M 0 s Flow hone O C C NA hA hA t 15.8 AC motor Man al O C C A5 15 M,K 45 D t 1 u Flow hone O C C NA hA hA t 23.7 AC motor Manual O C C A5 15 M,K 45 0 t l m Spring Manual C C C C A,M,1 15 A t v.a DJ.6 Spring Manual C C C C A M,1 lb o t,a J3.6 5pring Manual C C C C A,M,1 15 0 t,a 42 Spring Manual C C C C A,M,1 15 0 t,a AC motor Manual C 0 C A5 15 m,M,1 45 s 5,a 10.7 AC motor Manual C 0 C A5 15 A,M,1 45 0 s,a spring Manual C C C C A M,1 15 A t,a 5.3 Spring Manual C C C C A.H,1 15 0 t,a 25.7 5pring Manual C C C C A.M.I 15 0 t,a AC motor Manual C 0 C A5 15 A,M,1 45 A s: 7.4 AC motor Manuel C 0 C A5 15 A.M,1 a5 C s.: AC motor Manual C 0 C A5 !$ hone hA 8 5 6.0 AC motor Manual C 0 C A5 15 Mone hA 8 s Amenownt la, ul/co i

Page 33 of 33 HCGS - FSAR TABLE 6.2-16 (Cont'd) (9) Post-Accident valve position (open or closed) is the position during the initial 10 minutes after an accident. (10) Shutdown valve position (open or closed) is the position beyond the initial 10 minutes after an accident. (11) The ESF System designation is applied to primary containment penetrations that are a part of an ESF System and where that part of the system provides or aids a function that is characteristic of an ESF System. Although re-activity control systems are not usually characterized as being ESF Systems, .in this table reactivity control system penetrations are given the ESF system designation. (12) Manual indicates remote manual initiation of valve closure from the main Control room. (13) The secondary mode of operation is AC motor. ] (14) Operation is by local manual hand wheel. -(15) Deleted ] (16) The valve actuator is only used to exercise the valve disk during testing. (17) This is a spring loaded piston-actuated check valve. When the valve operator is in the open position, it will not resist valve closure. In this position the valve will function much like a simple check valve. In the de-energized position, the spring-loaded piston will assist in closing the valve.

However, it will not close the valve against flow from the normal direction.

(18) The isolation signals for his valve are generated to provide proper system alignment for ECCS injection. By assuming the ECCS injection position, the valves also provide a containment isolation function. (l9) Tnwe vacWS Aes sei.te i> meru etR % A M m cw % Aub THG LEAkW:S 15 IOCLLGM=D IQ TH 6 0.(Ola. CRCTEPA Ct' bVME1JOX [. } h Mh Y N b ~ \\ THe t=6ECt@T96 Ln365 AML> Hexcci APs TGSTED 10tTu W4 TSP AT j

l. lop. /EARA$s f Pan ALL VAttE5 17 LJM asi> To 16 GDN.

t T1002775 Amendment 14, 01/86

HCGS PSAR 07/E5 [ TABLE 6. 2-24 P1qa 1 of 17 l CONTAINMENT PENETPATIONS/IS3LATION VALVE COMPLI ANCE WITH 10 CPR 50, APPENDIX J Inboard Isolation Cutbotr:1 Inolation renet PCID Test Barrier Description / Parrier Description / tu ber Number

System Description

Type, Valve _ Number Notes valve Number N3tes P 1A M-41 Main steam line A AB V028 6

AD-V032, AD-V059, 6 FP-V010 P 1B M-41 Main steam line B AB V029 6 AB-V033, An-V060 6 FP-V000 P IC M-41 Main steam line C AB V030 6 AB-V034, AD-V061, 6 FP-V008 P 1D M-41 Main steam line D AB-V031 6 AB-V035, An-V062 6 FP-V007 P 2A M-41 Teedwater i C AE-V003 AE-V002 AG-6tol l AE-Voze#, Bd-veos _ P 2D M-41 Peedwater C AE-V007 AE-V00 6, AE-h l AE-ht, RT-Vos9 P3 M-51 RHR shutdown cooling C BC-V071 BC-V164 14 suction A,C BC-PSV-4425 7,17 P 4A M-51 RRR shutdown cooling return C PC-V014 PC-V013 C BC-V119 P 4B M-51 RHR shutdown cooling return C BC-V111 DC-V110 C BC-V117 P 5A M-52 Core spray to reactor C B E-V 002 DE-V003 l C BE-V072 P 5B M-52 Core spray to reactor C BE-V006 BE-V007 C BE-V071 PJ-V001 P 6A M-51 LPCI C BC-V005, BC-V122 DC-V004 l P 6B LPCI C PC-V017 BC-V120 PC-V016 P 6C LPCI C PC-V114, BC-V119 BC-V113 l P 6D LPCI C PC-V102, PC-V121 BC-V101 l P7 M-55 HPCI turbine C PD-V001 m Fn-V002 e steam supply PD-V051 Amendment 11 l

HCGS FSAR 1/85 l TABLE 6.2-26 (conti Page 2 of 3 Line valves *> operator Essential / Isolation ' Comments l Isolated' Number Number Non-Essential Signalst28 eas Station Service BC-V039 HV-F07$ Non-Essential None E Water FD-V032 None F BD-V023 None F BD-PSV-F017 None G BJ-PSV-F020 None-G UdSFRI ~ NOTES: j (18 Where a single containment isolation valve is used,- HCGS takes credit for the connecting system being a closed system outside primary containment (as defined in Regulatory Guide 1.141). In the case of a single failure, the closed system j accommodates the failure by being an extension of the containment. The intersystem valves assure the integrity of the extended containment boundary. l These valves meet all the requirements of primary containment isolation valves including the NUREG-0737, Item II.E.4.2 requirements.

*
Table of Isolation Signal Codes l

A - Reactor vessel Lov Water Level - Level 2 B - Dryvell High Pressure C - Reactor Building High Radiation j D - Reactor vessel Lov Water Level - Level 3 (3) Comments i j A. Using two intersystem isolation valves is conservative. If there is a single l failure, and the containment isolation valve is unable to close, HCGS assumes j credit for the closed system outside primary containment to accommodate the j failures only one intersystem isolation valve in conjunction with the containment isolation valve is required to assure that the integrity of the j closed system serving as an extension of the primary containment is j maintained. If the single failure is loss of the intersystem isolation valves, the containment isolation valve vill still be functional. Hence, the j closed system would not constitute an extension of the primary containment and a second intersystem valve vould not be required. B. The post-accident sampling system is a fail-safe system, and will isolate on 1 - loss of power. The system meets the requirement of a sealed closed system. Power to open the system is provided only under administrative control. I j Arendment 9 l i

INSERT FOR TABLE 6.2-26 PAGE 2 OF 3 BC-PSV-F029 None H BC-PSV-F030A None H H. BC-PSV-F030B None BC-PSV-F030C None H H BC-PSV-F030D None

HCGS FSAR 1/85 l q TABLE 6.2-26 (cont) Page 3 of 3 C. Although the system is classified as non-essential, if the system is functional, it vill be necessary to open the containment isolation valves after an accident, in order for the system to perform its intended function. D. Deleted. l E. The valve is seal closed. F. Use of a check valve as a system isolation valve is acceptable because it is located below the suppression pool and vill be maintained closed in the reverse flow direction by the hydrostatic pressure in the suppression pool. G. Use of a relief valve in the forward flow direction as ar isolation valve is acceptable because its set pressure is greater than 1.5 times the containment pressure. The set pressure is 100 psig. Drain valves, vent valves, and manual valves under administrative control have

- )

not been identified in this table for simplicity. Itavever, they are identified in Figures 6.2-45, 6.2-46, 6.2-47, and 6.2-48. I k W USE 6 h FELMF VAlv6 WJ W R:ewARD FtDub OtPJcrio.) As NJ ISOLATEM VALUG ts ACQgi.iAg(g becAusg tis g MSagg,$ ggggypng 3,4ag LS ~DHEC TVC 0%3TAINI(GrJT FRESSOPE, TH6 G6T PR6ssues is I%Ps%. Amendment 9 l a _i

BD V046 l E-teC-PRIMARY RPV CONTAINMENT BD V013 V~ { BD VD47 i # AE V015 y I FROM i y - F RCIC TAE V016 BD V005 (TYPICAL j^ gg FOR HPCl) D ~ X )> FEEDWATER g, w

LIN E AE V004 AE V003 AE V002 AE V001

\\ 3 - lP2Al Us AE V075 AE V139 J. 3 AE V020 l:' [ 4' ] AE V140 ]," AE V074 J

AE V019 LJ

. AE V138 ISOLATION VALVES ^ M P2A I P 28 IAE V141 ( ' ',' ' ' 1 ,w AE V003 { AE V007 AE V021 AE V002 l AE V006 FD AE V021 l AE V021 BG V071 TO THE OTHER FEEDWATER LINE BD V005 l BJ V059 , 7 AE V001 l AE V005 Ip*s BG 8072 a, TEST /DR AIN VALVES AE V128 l l P 28 P2A DETAIL 2 l l f AE V018 I AE V020 AE V019 l AE V017 M AE V015 l AE V014 .....'.,l _ _ _ _ _ _4. _ _ _.!.. _ _ _ _ _...{, )> _ _ _ _ AE V016 l AE V013 l AE V008 r-4 g......, AE V005 l FROM l.S2..B, j e BG V072 BG-V071 l AE-V075 l AE V074 l HOPE CHEEK BD-V047 i BJ V018 ^ FINAL SAFETY ANALYSIS REPORT AE V004 I AE V008 AE V127 l AE V128 % (SEE LEGEND) FIGURE 6 2-28 SHEET 2 OF 48 Amendment 14,01/86 =

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4 4 3 1 2 SHEET 3 OF 3 Amendment 13,11/85

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HCGS FSAR 8/83 such as prestartup valve lineup' checks, suffice to reasonably ,)(' ensure that such valves will not degrade ECCS performance. Ccrtain Other c 1ecc are phycically leched in their n rmal peritier ^ccerr to the keys to the IOcht 10 C0r.tr0lled

dministratiJclytf In other cases, two isolation valves are provided in series to minimize the possibility of inter-or intra-system leakage.

Position indication of manual valves that are in the main flowpaths of the ECCS, and that are inaccessible during normal plant operation, is provided in the main control room. Proper administrative controls and/or surveillance testing are relied upon to ensure the position of the remaining valves. 6.3.2.9 TMI Action Plans See Section 1.10 for a discussion of TMI Task Action Plan requirements applicable to HCGS. 6.3.3 PERFORMANCE EVALUATION The performance of the emergency core cooling system (ECCS) is determined through application of the 10 CFR 50, Appendix K evaluation models, and demonstrated conformance to the acceptance criteria of 10 CFR 50.46. The analytical models are documented in Section S.2.5.2 of GESTAR II (Reference 6.3-3). The ECCS performance is evaluated for the entire spectrum of break sizes for postulated LOCAs. The accidents, as listed in Chapter 15, for which ECCS operation is required are: a. Section_15.6.6 - Feedwater piping break b. Section 15.6.4 - Spectrum of boiling water reactor (BWR) steam system piping failures outside of containment c. Section 15.6.5 - LOCAs Chapter 15 provides a description of the radiological consequences of the events listed above. sw 6.3-30 Amendment 1 ~.

HCGS FSAR / ( a. Two 1005.-capacity air handling units, including low and high efficiency filters, fans,. chilled water cooling coils, and electric heating coils, are provided for use during normal operation or following an accident. Electric pan humidifiers are provided for use during normal operation. b. Two 100%-capacity return air fans are provided for use during normal plant operation and following a design basis accident (DBA). c. Two 100%-capacity emergency air filtration units are provided for use following an accident. Each unit has its own fa,n, low efficiency prefilters, electric heating coils, upstream high efficiency particulate air (HEPA) filters, charcoal adsorbers, and downstream HEPA filters. d. An exhaust fan is provided.to exhaust air from the control room, and toilet facilities during normal operation. VrrH MENOH T W M y!4{ A Two separate outside air intake 34are provided for use Osmgx Mcp e. g ggg)TuS6 during normal operation or following a DBA. f. The dampers for control room isolation purposes are bubble-tight with a closure time of 5 seconds maximum. 6.4.2.3 Leaktichtness Control room envelope construction joints and penetrations for cable, pipe, HVAC duct, HVAC equipment, dampers, and doors are designed specifically for leaktightness. A list of potential leak paths to the control room is provided in Table 6.4-1, along with the type of material, joint, or penetration. Periodic tests to verify control room leaktightness are discussed in Section 6.4.5. The control room envelope is constructed forVan outleakage rate of less than 1000 cfm at 1/8-inch water gauge positive pressure relative to the control room adjacent areas. The 1000 cfm leakage rate is equivalent to 1.1 control room volume changes per 7 ( ~ 6.4-5 l

HCGS FSAR 1/85 system consists of two 100%-capacity trains, each supplied by a l separate Class 1E power system and interlocked with one of the CRS/CRRA systems. Each CREF train consists of an outside air connection to the CRS outside air intake plenum, radiation sensor, tornado damper, smoke detector, outside and return air dampers, fan, 80 to 85% ASHRAE dust spot efficiency filters, electric heating coil for humidity control, upstream high efficiency particulate air (HEPA) filter, charcoal adsorber, a downstream HEPA filter, and a discharge damper. The CREF system may' operate in one of the two following modes: A pressurizing mode in which 1000 cfm of outside air is a. mixed with 3000 cfm of control room return air before entering the CREF unit, thus pressurizing the control room envelope above the surrounding space This mode is an automatic mode following a detection of high airborne radioactivity in the control room normal air intake. b. The operator can override the control room pressurization mode to initiate isolation mode by manually closing the outside air intake isolation damper for the operating CREF unit. However, this mode IMW.I is nottused following a radiological accident. The recirculation (isolation) mode is circulating 4000 cfm [- of return air, without introduction of outside air, through a CREF unit. 6.4.4 DESIGN EVALUATIONS The control room habitability system is designed with redundancy and separation of active components to provide reliable operation under normal conditions and to ensure operation under accident conditions. The design basis accident (DBA) radiation source terms used for control room dose evaluation are in accordance with NUREG-0737, Item III.D.3.4., Control Room Habitability Requirements. 6.4.4.1 Radiological Protection A detailed discussion of the dose calculation model for control' room operators following the postulated DBA is provided in Section 6.4.7. r 6.4-8 Amendment 9

HCGS FSAR 1/85 (L ~ The design basis accidents have been evaluated to determine the worse case accident scenario for control room habitability design purposes. The control room operator doses can be derived for each of the' accidents by the methodology described in Section 6.4.7 with the radiation source terms defined in the appropriate sections in Chapter 15 and the release locations relative to the control room intake shown in Figure 6.4-2 and Table 6.4-6. The release location for the DBA LOCA, fuel handling accident, main steam line break accident and instrument line break accident which occur inside primary containment and the reactor building is the FRVS exhaust vent at the top of the reactor building. The release location for the control rod drop accident, main steam line break accident, and offgas system failure which occur in the turbine and radwaste buildings is the south plant vent. The offgas system failure could also result in releases from the north plant vent depending upon the actual accident location in the building. The release location for the main steam line break accident which occur in the main steam tunnel is the blowout panels located between the reactor building and the south plant vent. The release location for the HPCI steam supply line break accident, which occurs in the reactor building at elevation 63'- 0", is the reactor building blowout panels located in the west wall of the reactor building. The radiation source term for this I13 5E' r accident can be conservatively assumed \\ equivalent to the main steam line break for purposes of this evaluation. /Thc c;pcctcd I rrc releccc ic apprcrimately SCt Of the men. ctccr li.7 bccek which uculd result in c Tuch Icuer ccurce tcrr. I \\ Of all the accidents' releasing from the FRVS exhaust vent, the highest source term Dnc icnacct curctice. results from the DBA LOCA. Releases from the south plant vent occur from accidents which have lower source terms and a smaller atmospheric -(dispersion factor w)th respect to control room intake LOCA. rurtner, citr.cuar, p e main steam line break and HPCI line break J have htehedgsource termsi the duratier c! the accident ir rherte0 INMMAA,L in comparison to the DBAILOCA. Therefore, the consequences are less. Consequently, the DBA LOCA has been determined to result in the controlling accident conditions and has been designated the worst case accident scenario for control room habitability design purposes. The resulting calculated doses for control room occupancy on a rotating shift basis, for the reactor building design basis inleakage rate, are shown in Table 6.4-4'and are less than 5 rem to the whole body or the 9 6.4-8a Amendment 9

(_ HCGS FSAR d. f, Time averaging effects - Wind speed variation and 3 wind direction meandering effects are not modeled in wind tunnel tests. To account for this effect, NUREG/CR-1474, indicates that the following formulation should be used: -1/2 C = C, (t /t,) (6.4-4) P p where: C prototype concentration = p m del concentration C = m prototype sampling times t = model equivalent field sampling times t = [ Therefore, scaling 3 to 10 minute wind tunnel data up to 1-hour X/Os results in a reduction factor of 0.4. Scaling from wind tunnel data to 8-hour X/Os would result in a reduction factor of 0.14. Time averaging effects can have large effects in the calculated X/Os, but these effects have not been tested fully for building wake conditions. Therefore, a value of 0.5 for f is 3 conservatively estimated. Based upon the above parameters, an X/O was calculated as follows for the O to 8-hour time per_iod: X/O = K_ x f x f, x f xfxf 3 3 3 AU For the diesel exhaust, ( /0) DE = 3 x1x 1 x 0.2.x 1 x 0.5 ,a x 1.28' (4T601 d 6.4-17

HCGS FSAR The removal constant,A for loss of activity due to outleakage, L, assuming that air leaves the control room at the same rate which it enters, is given by: (F+FJ60) g,kr,,,,2 (6.4-8) A v T For activity entering the main control room during the period of interest ~, the following equation is obtained: dI, = O-(AD + AR + AL) Is (6.4-9) dt where: inventory of radioactivity in the control room due to I- = the activity that enters during the period of interest, Ci time from initiation of the event, h t = Solving equation 6.4-9 for I using the initial conditions that 3, In = 0 at t = t and O equal to a constant for the period, yields i the following equation: I = 0 [1 - exp - (A (t-ts))] (6.4-10) t t A t where: A +A +A A = t D R L time at the beginning of the period of interest, h t = i / s 6.4-21

HCGS FSAR r~ I 6.8 FILTRATION, RECIRCULATION, AND VENTILATION SYSTEM The filtration, recirculat' ion, and~ ventilation system (FRV'S) consists of two subsystems that are required to perform post-accident, safety-related functions simultaneously. -These subsystems are: a a'. Recirculation system - The FRVS. recirculation system is an engineered safety feature (ESF) system, located inside the reactor building, that reduces offsite doses significantly below 10 CFR 100 guidelines during a loss-of-coolant accident (LOCA), refueling accident,'or high radioactivity in the reactor building. Upon reactor building isolation,.the FRVS recirculation system is actuated and recirculates the reactor building air through filters for cleanup. This subsystem is the initial cleanup system before discharge is made via the FRVS ventilation subsystem to. the outdoors. b. Ventilation system - The FRVS ventilation system is an ESF system, located inside the reactor building, that maintains the building at a negative pressure with respect to'the outdoors. The system takes suction from the discharge duct of the FRVS recirculation system and discharges the air through filters to the outdoors via a vent at the top of the reactor building. 6.8.1 FRVS RECIRCULATION SYSTEM 6.8.1.1 Desion Bases The FRVS recirculation system is designed to accomplish the following objectives: a. Recirculates and filters the air in the reactor building following a LOCA, or other high radioactivity accident, to reduce the concentration'of radioactive halogens and particulates potentially present in the reactor building. See Figure 9.4-3 for design airflow rates in the reactor building. The circulating rate is ggg pf reactor building free volume per minute (, 3 94 6.5-1

i l HCGS FSAR 01/86 l The filter-demineralizer system also services the torus water cleanup system for the purification of suppression pool water. The stainless steel filter-demineralizer vessels are of the pressure precoat type. A tube nest assembly consisting of the tube sheet, clamping plate, filter elements, and support grid is inserted as a unit between the flanges of the vessel. The filter elements are stainless steel and are mounted vertically in the vessel. Air scour connections are provided below the tube sheet, and vents are provided in the upper head of each vessel. The filter elements are installed and removed through the top of each vessel. The holding elements are designed to be coated with powdered ion exchange resin as the filtering medium. The fuel pool filter-demineralizers maintain the following effluent water quality specifications: Specific conductivity at 250C, micromho/cm 50.3 l pH at 250C 6.0 to 7.5 Heavy elements (Fe, Cu, Ni), ppm <0.05 ( s Silica (as SiO ), ppm <0.05 2 Chloride (as Cl-), ppm <0.02 Total suspended solids, ppm 90% removal to a minimum of 0.01 ppm plF 4e EFF-The influent and effluent water of the spent fuel pool filter LuENT demineralizer is continuously monitored by on-line pH and W4U9t/EEconductivity instrumentation. In addition, grab samples of the L-a> analyzed weekly for C1, suspended s_olids, silica, and gamma isotopics, and monthly for the heavy elements. Decontamination factors (df) of > 10 are expected for any Cl-and suspended solids and > 5 for isotopes of I and Co. Resin beds will be regenerated and/or replaced when these df's are not achieved. The spent fuel pool demineralizer will*be operated as required to maintain radiation levels on the refueling platform less than 2 mrem /hr. 9.1-31 Amendment 14 l r

HCGS FSAR 10/84 ( extruder / evaporator turntables to the capper / scanner infeed conveyor and replaces them with empty drums. kk. Solid radwaste bridge crane (00H317) This 7-1/2-ton double girder. crane is located above elevation 102 feet in the auxiliary building. It also serves the radwaste drum storage area loft at elevation 126.5 feet. It moves filled 55-gallon drums within the ~ storage area, unloads the outfeed conveyor, assists in removing the shipping cask lid, and in truck loading. 11. SACS pumps hoist W. BRED 10 4-T8431pbeK-NG(MNb#y Fifteen-tonfcapacitymonorails)abovetheSACSpumps ARF munup#

cne: to accommodate hoists for removal of the pump

,f' motors. One monorail serves pumps A and C in SACS loop l >EDeJ ; A, and the other_ serves pumps B and D in loop B. The monorails are located above elevation 102 feet in the reactor building. The top of each rail is at elevation 126 feet 10.75 inches. Because dedicated SACS pump hoists were not purchased, they will be borrowed from ( other locations when needed. mm. SACS heat exchanger hoist Two parallel 5-ton capacity monorails at one end of each SACS heat exchanger are designed to accommodate hoists for removal of the heat exchanger end covers. One set of monorails serves both SACS loop A exchangers, and the other set serves the loop B exchangers. The monorails are located above elevation 102 feet in the reactor building. The top of each rail is at elevation 127 feet 1 1/2 inches. Because dedicated SACS heat exchanger hoists were not purchased, they will be borrowed from other locations when needed. nn. Recombiner system hoists (00H318, 10H318) These 1-1/2 (00H318) and 2-1/2 (10H318) ton capacity chain-operated monorail hoists are located above elevation 67 feet 3 inches in the service and radwaste ( 9.1-98 Amendment 8

i s 13

f G 5I d REGION OF APPR ED 14 g VOLUME CONCE TRATION P 13.8 = = l r LOW Z LEVEL U ALARM OVERFLOW b 13 4 "

VOLUME 5

l12.9a / i3 w = MINIMUM REQUIRED CONCENTRATION LINE f 12.0 4400 4500 47 4700 4800 4900 5000 100 5200 ^ 4750 4990 NET TANK VOLUME (GALLONS) tESTG 4MD REPLACB wrra Tne reorwiuG l HOPE CREEK GENERATING STATION FINAL SAFETY ANALYSIS REPORT ~ SODIUM PENTABORATE (Na B 0 .10H O) 2 3o 16 2 VOLUME CONCENTRATION REQUIREMENTS FIGURE 9.3 9 - - - ~ - - - ~ - - -

) i ~ REGION OF APPROVED g 15 - CONCENTRATION VOLUME ACCEPTABLE OPERATING REGION - ENTIRE ZONE 5 HIGH G LOW [ LEVEL LEVEL OVERFLOW _7,.. ALARM ALARM LEVEL 5 U l I l f 1 ' E 13.S a = i V t EXPANSION g ,p. u VOLUME ) 8 5s. MINIMUM REQUIPED i N 22s. CONCENTRATI0fl LINE \\ 12.0 l 4400 4500 4600 4700 4300 4930 5000 $100 5200 4630 4a50 4997 5053 NET TANK VOLUME (GALLONSI fil: HOPE CREEK GENER ATING STATION FINAL SAFETY ANALYSIS REPORT SOOlUM PENTABORATE l j (Na B 016 10H O) 2 10 2 VOLUME CONCENTRATION REQUIREMENTS FIGURE 93 9

^ ,D D N \\ g IICGS FSAR 5/05 l l TABLE 9. 5-3 (cont) Page 3 of 5 Approximate UdleIlal_ge3EEAE112D Quant it y Plant Location Condition of Use Time of Use Air bottle 1 at 230 scf Circulatirg water 2200 psig Intermitt ently - air sup-l structure, ply for fire protectior l el 106'-0" sprinkler system. l Liquid petroleum qas 6 at 100 lbs Yard - next to 20 psig Intermittently - (ignition l bottles auxiliary boiler of auxiliary boilers) l building (west side) l llWh* cogr_oa ives_[ acids. _ caust ical Sulfuric acid 21,000 gal. Yard-near cooling towers Solution, 660 De continuous Sodium hypochlorite 90,000 gal. Yard-near cooling towers Solution 15% by wt 90 min /diy Sodium hypochlorite 45,000 gal. Yar3-near intake Solution 15% by wt 90 min /dsy structure Sodium hypochlorite 55 gal. drum Aux boiler b1dg domestic Solutior.15% by wt 12 h/ day water tanks (yard) l Caustic soln 150 gal. Aux bldg --cor. trol Solution 50% by wt 90 min / day area, el 121' Caustic soln 200 gal. Aux bldg - RW/ service Solution 25% by wt 16 h/ day (re f uel ir g) area, el 124' 5-1/2 h/ day (normal) Caustic soln 250 gal. Aux b1dg - cortrol Solution 4% by wt 30 min /2.5 days area, el 102' Sulfuric acid 250 gal. Aux bidq - cor. trol Solution 4% by wt 30 min /2.5 days area, el 102' Caustic, tank OOT-140 16,000 gal. Turb bid), el 54' solution 50% by wt 2.5 h per reger of I service vessel resir per 30 days ) Sulfuric acid 16,000 gal. Turb bldg, el 54' solution, 60' De 2.0 h rer regen of 1 service vessel resin per 30 days Caustic, tank 00T-141 16,000 gal. Turb bidg, el 54 ' solution 50% by wt . Sulfuric acid 16,000 gal. Turb bldg, el 54' Solution, 60* De Sodium Fer.taborate soln, 5388 gal. RB, el 162' Liquid (fsed to shut down reector SLC storage tank following scram tailure (5 1 time /40 yr) Amendmeet 10 l

I j i INSERT FOR TABLE 9.5-3 PAGE 3 OF 5. 2 Nitrogen Bottles 12 at 304 ft' Emergency Diesel 165 psig Intermittently - j each (6 per Generator Fuel maintains SACS-accumulator) Oil Storage Area, accmumlator tanks 3 EL 54', Room 5106 water.. level as required i ) 1 i 4 k 4 I 1 b b I ( 1 l 1

HCGS FSAR l \\' 11.2 LIQUID WASTE MANAGEMENT SYSTEM The liquid waste management system (LWMS) is designed to collect, store, process, and dispose of or recycle all radioactive or potentially radioactive liquid waste generated by plant operation or maintenance. The LWMS consists of five process subsystems, each for collecting, storing, processing, monitoring, and disposal of specific types of liquid was'tes in accordance with their conductivity,. chemical composition, and radioactivity. These systems are: a. Equipment drain (high purity waste) b. Floor drain (10w purity waste) c. Regenerant waste (high conductivity waste) d. Chemical waste (decontamination solution waste and chemistry lab drains) e. Detergent drain waste (laundry waste and personnel ~ decontamination drains). These systems are shown on Figures 11.2-1, 11.2-2, 11.2-3, and 11.2-4. Equipment locations are shown on drawings provided in Section 1.2. The radioactive waste drainage system, a major input source to the LWMS, is described in Section 9.3.3._ The equipment and floor drainage collection system in shown on Figure 9.3-7. M AL-Sufficient treatment apability is available to process liquid MEb WWER waste to meethrer.ccr:2 c quality requirements for plant reuse i (conductivity value of @tTthe quality requirement for reuse are ,umho/cm at 250C). Liquid wastes that [bh cannot be processed to mee solidified along with process concentrates for offsite shipment and disposal. Excess water is released in a controlled and monitored manner into the cooling tower blowdown line for dilution and then discharged to the Delaware River. k N 11.2-1

HCGS FSAR -10/84 i corresponding noble gas release rate of 500,000,Ci/s after 30 minutes decay (design basis). i The concentration of radioactivity at the point of discharge shall not exceed concentration limits specified in 10 CFR 20, on an annual average basis. g. All piping and equipment in the LWMS are non-Seismic Category I with the exception of the primary containment. The seismic category, quality group classification, and corresponding codes and standards that apply to the design of the LWMS are discussed in Section 3.2. h. Design features that reduce maintenance, equipment downtime, liquid leakage, or gaseous releases of radioactive materials to the building atmosphere, to facilitate cleaning or otherwise improve radwaste operations, are discussed in Section 12.3. ( i. All atmospheric liquid radwaste tanks are provided with an overflow connection at least the size of the largest inlet connection. The overflow is connected below the tank vent and above the high level alarm setpoint. It is routed to the nearest drainage system compatible-with its purity and chemical content. Each liquid radwaste tank room is designed to contain the maximum liquid inventory in case the tank ruptures. j. Processed wastes are7 collected in sample tanks prior to their reuse asNee#wsensate quality water or discharged IN M EI in a controlled manner into the cooling tower blowdown line for dilution before entering the Delaware River, k. The expected and maximum radionuclide activity inventories for LWMS components containing significant amounts of radioactive liquids are shown in Tables 11.2-8 and 11.2-9. They are based upon the assumptions given in Table 11.2-1 and upon the following: 11.2-3 Amendment 8

HCGS FSAR p, 10 umho/cm and less than 20 ppm suspended solids) and are ks processed on a batch basis through a precoat filter and a mixed-bed demineralizer. Cross-connections with the floor drain subsystem allow processing through the floor drain filter and demineralizer. The processed wastes are collected in one of the two waste sample tanks for chemical and radioactivity' analysis. If acceptable, the tank contents are returned to the condensate storage tank. (CST) for plant reuse. A recycle routing from the waste samplefu ' DENN. tank allows the sampled water that does not meet thetseneensaea EtudEp quality requirements to be pumped back to a waste collector tank hMnuR for additional processing by filtration and demineralization, or to the waste surge tank for transfer to and processing in the regenerant waste subsystem. If the plant condensate inventory is high, the sampled waste water is discharged to the cooling tower blowdown line for dilution prior to discharge to the Delaware River. Additional collection capacity is also provided by a waste surge tank tied to the common inlet header of the waste collector tanks. 11.2.2.1.2 Floor Drain Processing System The floor drain collector tanks receive low purity waste inputs from various floor drain, dirty radwaste (DRW), sumps in each plant enclosure and other inputs listed in Table 11.2-7. These wastes typically'have a conductivity of 10 to 100 umhos/cm, a maximum suspended solids concentration of 500 ppm, and a radioactivity concentration of less than 10-3 uCi/cc. The floor drain subsystem consists of two floor drain collector tanks, a precoat filter, a mixed-bed demineralizer train, and two sample tanks. The wastes collected in the floor drain collector tank are processed on a batch basis. Cross-connections with the equipmer.t drain subsystem also allow processing through the waste filter and demineralizer train. The floor drain sample tanks collect the processed wastes, so that a sample may be taken for chemical and radioactivity analysis before discharge. The discharge path depends on the water quality, cooling tower blowdown availability, and plant water inventory. The treated floor drains may be discharged from the plant to the Delaware River after mixing with the cocling ( l 11.2-6 f

HCGS FSAR tower blowdown. _Off-standard quality water can be recycled to the floor drain collector tanks or to the waste neutralization If the I N W. tanks to be processed in the recenerant wastep:ubsystem. 1 treated wastes meet the standards for^cendenr_ = water t r! ira. _ used in the plant, and if the water inventory permits their recycle, the processed floor drain waste can be discharged to the CST for plant reuse. 11.2.2.1.3 Regenerant Waste Processing Subsystem The regenerant waste subsystem collects wastes from the regeneration process for the condensate and radwaste demineralizers and the high conductivity drain sumps in the radwaste area of the auxiliary building and the turbine building. These wastes are collected in the waste neutralizer tanks, where they are neutralized and, if required, buffered with solutions of sodium phosphate before being processed through the waste evaporators for concentration. The distillate resulting from the evaporation process is returned to the waste collector tanks. The waste evaporator concentrate is collected in the concentrated waste tanks for chemical pretreatment and is transferred to the-solid waste management system (SWMS) for solidification and y offsite disposal. In addition, concentrate is transferred from ( the decontamination solution concentrated waste tank to the concentrated waste tanks. 11.2.2.1.4 Chemical Waste Processing Subsystem Chemical wastes collected in the chemical waste tank consist of laboratory wastes, decontamination solutions, and sample rack drains. After accumulating in the chemical waste tank, these wastes are neutralized to a pH value of 7 to 10 and, if required, buffered with a solution of sodium phosphate, then processed by evaporation through the decontamination solution evaporator. The chemical wastes are normally evaporated to reduce volume. The concentrate is discharged to the decontamination solution concentrated waste tank for radioactive decay, then transferred to the concentrated waste tanks. The vapors produced during this evaporation are sampled and discharged through the south plant vent. When the radioactivity concentration is low, a cross-connection with the floor drain subsystem allows the chemical wastes to be processed through the floor drain filter and demineralizer and then diluted with the cooling tower blowdown prior to discharge to the Delaware River. 11.2-7

HCGS FSAR 1/84 11.2.3 RADIOACTIVE RELEASES During liquid processing by the liquid waste manaaement syster 'LWMS), radioactive contaminantsy6re removed so that the bulk of tne 11guld is restoreo toh.n nc &c::: cu2.. n ca t e n, which is. magggggy either returned to the condensate storage tank (CST) or discharged to the environment via the cooling tower blowdown line. The radioactivity removed from the liquid wastes is concentrated in the filter media, ion exchange resins, and evaporator bottoms. These concentrated wastes are sent to the solid waste management systems (SWMS) for further volume reduction and solidification. If the liquid i g ecycled to the l CCrl plant, it meets the purity r,equirements lofgr:rcen 2:a makeup, as discussed in Section#: L.O.=7N-If the liquid is discharged, the ~ ~ f9.; 31 activity concentration is consistent with the discharge criteria of 10 CFR 20. Tritiated water that is discharged from the systems is consistent with the discharge criteria of 10 CFR 20. The resulting doses from radioactive effluents are within the guideline values of Appendix I of 10 CFR 50. In addition to the radioactivity limitations on releases, water quality standards for discharge and heat content may necessitate recycling of the ( water rather than discharging. Although the plant discharges vary as stated above, this analysis assumes the following, consistent with NUREG-0016: a. Discharge of 1% of the high purity waste processing stream b. Discharge of 50% of the low purity waste processing stream c. Discharge of 10% of the chemical waste processing stream d. Discharge of 10% of the regenerant waste processing stream e. Discharge of 100% of the laundry drain waste processing stream. The assumptions and parameters used to calculate the yearly activity releases are given in Table 11.2-1. The yearly activity l 11.2-11 Amendment 4 I

HCGS FSAR 10/84 C e. Continuous monitoring is provided for all potential PR$R TO\\ cathways of airborne radiopctive releases, with main Ek control room annunciatiohuct 1 c 1; '.i;her th:d allowed TecuuCAL 1imits. ] spens:scA f. Design provisions are incorporated that preclude the uncontrolled release of radioactivity to the environment as a result of any single operator error or any single active component failure. g. The GWMS is designed to keep the exposure to plant personnel as low as is reasonably achievable (ALARA) during normal operation and plant maintenance, in accordance with Regulatory Guide 8.8. h. The offgas system is designed to provide at least 35 days and 36 hours of delay time for xenon and krypton, respectively, at 75 scfm airflow rate. i. The offgas system is designed in accordance with the guidelines of Regulatory Guide 1.143, with the (' '\\ exceptions described in Section 1.8. A j. Filtration units in the ventilation systems are designed, operated, and maintained in accordance with the guidelines of Regulatory Guide 1.140. k. The offgas system is designed to maintain the concentration of hydrogen in the gases exhausted from the main condenser below flammable limits. 1. Instrumentation is provided in the offgas system to detect abnormal concentrations of hydrogen and other system malfunctions. m. The offgas system is designed to withstand the effects of a hydrogen explosion without breach of the pressure boundary. I w 11.3-2 Amendment 8 1 6

HCGS FSAR 11/85 environmental :::

= conditions that can occur at its

[ location and has been procured in conformance with a 10CFR Part 50, Appendix B quality assurance program. The FRVSV RMS is powered from a battery backed uninterruptible ac power source. Except as described above, the FRVSV-RMS components and functions are similar to the NPV and SPV-RMS components and functions. FRVSV RMS calibration procedures are based on the-requirements of the operation and maintenance manual supplied with the equipment. Calibration frequencies are provided in Chapter 16, " Technical Specifications." 11.5.2.2.4 Cooling Tower Blowdown Radiation Monitoring System The cooling tower blowdown (CTB) RMS monitors a sample of the cooling tower blowdown before it is discharged to the Delaware (- River (Refer to Figure 10.4-3, Sh. 3). The high alarm indicates that abnormally high amounts of radioactive materials are being released to the environment; however, it is recognized that the seasonal natural content of potassium-40 in the river, after concentration in the cooling tower system, may cause upscale indication greater than actual plant releases. The CTB RMS has the same components as the liquid radwaste RMS (see Section 11.5.2.2.5), but enb associated LRP does not provide a trip for valve closure or measure process flow rate. 11.5.2.2.5 Liquid Radwaste Radiation Monitoring System The liquid radwaste RMS monitors the liquid radwaste sample for gamma radiation prior to discharge into the cooling tower blowdown line (Refer to Figure 11.2-2, Sheet 1). The liqu'id radwaste discharge is diluted by a continuous flow of water from the cooling tower basin prior to discharge into the Delaware River. A sample of the liquid radwaste discharge flows through. the liquid radwaste RMS. The discharge system is described in more detail in Section 11.2.3. Liquid radwaste can be discharged from any of several tanks collecting processed water. Prior to any release, the tank water is mixed thoroughly, sampled, and the sample is analyzed in the 11.5-16 Amendment 13 l

g i } s HC33 FSAR 1/R6 l 0 TABLE 11.5-1 (Page 1 of 6) HOPE CREEK RADI4 TION MONITORING SYSTEMS Minimum Number Detecta ble RMS Ide'stification of Detector Detector Concen-Descrigion, an 3 Re f. Channels Iypet1S8C468 Locatior.(t78 _Ranget:** tration(aaa 9a Main steam line 4 Gamma ion Downstream of 1-10*mP/h 1 mR/ht388 11.5.2.1.I chamber outboard REN006A MSIVs REN006B El. 137, Area 26 REN006C REN006D 2p.6 - 2= id ' 2nIo'# Refueling floor 3 Beta-Upstream '_'? - - ' r :pC/cc Xe-13 3 exhaust scint of damper /2 pc/cc 11.5.2.1.2 El. 205, Area 15 at 2.5 mR/hr RE4856A MFPCF8 RE4856B RE4856C 1r 56 - 2 6 to' g Lk#*T ,y Reactor buLiding 3 Beta-Upstream 0 ' C'pci/cc exhaust scint of damper fXe-133 pC/cc 11.5.2.1.3 El. 189, Area 15 at 2.5 mR/hr RE4857A MFP(F# RE4857B RE4857C Control room 2ca 8 Beta-Air inlet suih GkW ~ 2N80 m-Lei /cc Kr-8 W: -- aC/cc ventilation scint plena jo ,4at /hr 11.5.2.1.4 El. 162, Area 26 MF rs RE4858C RE4858C1 RE4858D RE4858D1 Drywell atmosphere 2 Gamma ion Inside 1-10 eR/h 1 R/ht**8 l po st-accident chamber containment MFP(78(188 11.5.2.1.5 El. 145, Area 17 FE4825A RE4825B Amendment 14 l

HCGS FSAR 10/84 7-- 12.1.3.1.2 Station Procedures Administrative requirements are implemented to ensure that applicable procedures developed by other plant disciplines have adequately' incorporated the principle of minimizing personnel exposure. Station administrative documents describe the criteria for selection of those procedures and revisions that are reviewed by radiation protection. Recommendations made by radiation protection normally are resolved with the appropriate plant discipline prior to submission for final review and approval. l Procedures are subject to revision whenever improved techniques ~ or increased safety are indicated. 12.1.3.2 Station Orcanization RAoATied Retrs/ As described in ection 12.5.1, the station organization provides OEmdmV thetz dictier rrete t:cr enciner: with direct access to the / FhNA5R j'eneral, manager to ensure uniform support of radiation protection l x apd ALARA requirements. This organization allows the # neral p nager direct involvement in the review and approval of specific ALARA goals and objectives, as well as review of data and dissemination of information related to the ALARA program. I The station organization includes a,d'enior /'adiological /ngineer j who is free from routine radiation protection activities to implement the station ALARA program. This individual is primarily responsible for coordination of station ALARA activities and routinely interacts with first-line supervision in radiation work planning and post-job review. 12.1.3.3 Operatina Experience Experience gained during the operation of Salem Units 1 and 2, along with information from other boiling water reactors (BWRs), serves as the basis for procedures, techniques, and administration controls for HCGS. In addition, the radiation work permit process described in Section 12.5.3.2 provides a mechanism for collection and evaluation of data related to personnel exposure. Information collected by systems and/or components and job function assists in evaluating design or procedure changes intended to minimize future personnel radiation (, exposures. 12.1 14 ' Amendment 8 1 I E )

4 HCGS FSAR 11/85 [ and is responsible for all activities of the Technical Department. s The Technical Manager interfaces.with the necessary and ' appropriate departments and personnel in the performance of the department activities. The responsibilities of the Technical Department personnel are as follows: a. Technical Engineer: The Technical Engineer is responsible for the areas of reactor engineering, technical reports and procedures, thermal performance, equipment reliability monitoring and testing, and document control. Reporting to the Technical Engineer are the Senior Reactor Supervisor, Senior Technical Supervisor and the Senior Reliability and Performance-Supervisor. ;Tne scnior acceter surer":cer arrure: ;. and reopencibilit //h the absence of the - la u t hor i ty 1 f ggr Technical Engineerg i b. Senior Reactor Supervisor: The Senior Reactor Supervisor is responsible for reactor engineering and thermal performance and equipment reliability monitoring. Engineers are assigned to the Senior Reactor Supervisor to develop and implement the details of the programs. The reactor engineering group assists the Power Ascension Manager in the development and implementation of initial criticality, low power physics and power ascension test programs and provides technical direction to the operating department for thermal and nuclear operation of the reactor and initial core loading and refueling operations. The reactor engineering group also monitors, collects, trends, and analyzes performance data for systems important to plant efficiency and reliability. The Senior Reactor Supervisor reports to the Technical Engineer. c. Senior Technical Supervisor: The Senior Technical Supervisor is responsible for the administrative procedures, technical responses, and reports leaving the station in support of facility license and review of operating experiences. Reporting to the Senior Technical Supervisor are the staff engineers and the (( e 13.1-28 Amendment 13

4 INSERT'FOR PAGE 13.1-28 the aforementioned Senior Supervisors assume.the responsibility j and authority of the Technical Engineer in their-respective disciplines. 4 h I e l 4 3 5 h l i .I. k i 1 I j 1 ? i i 4 ..... - _., _. _... - _,. ~ _. _. -. - - -. -... - -. -.. - - _.,. ,-.~.

I HCGS FSAR 11/85 w 3 d. Senior Maintenance Supervisors: The Senior Maintenance Supervisors are responsible for assisting the Maintenance Engineer or I&C Engi'neer as applicable, in planning and executing maintenance repair sad inspection activities. They are responsible for the effective use of materials and manpower while conducting maintenar.ce.and repairs. They direct the activities of the Nuclear Maintenance' Supervisors. A Senior Nuclear Maintenance Supervisor, when so designated, will assume the authority and responsibilities of the Maintenance Engineer, or I&C Engineer, as applicable in his absence. The Senior Nuclear Maintenance Supervisors' 1 responsibilities include the following: 1 i 1. Scheduling.and coordinating department work assignments 2. Preventive. maintenance program l t \\ i Corrective maintenance program ~ l 3. 4. Technical Specification surveillance program l i i ,5. Support of initial startup program l i 6. Ensuring personnel certification is maintained l Y . i 0. Senier " inten:ne P1:nning Supervicer; The Senior l M:inten:ne Pl:n-ing Sup: viser r;perts to the teintensne: M:n ger nd :::ict: the M:inten:ne: M:n;ger i -in th: :::: Of dep rtment :drini:tr:tiv: :nd pl:nning -4 unction:. M in re p:::ible for th: ::intenene l Sirtery re:Orde, .mirtenance pler-ing for both the t d ily :nd t:ge ::tivitier, in pectier Order impic==ntation, obtaining==te:L=1 :na vena=: =upp=:t, J:rkl d tr:Ching, 2nd interf:00 cith the St: tier 1 _n.s.-_..._.._,

u.,_..- _,_ _..

l i i t i 13.1-31 Amendment 13 I ,I -.m.-.. q m m -m

+ HCGS FSAR 11/85 A licensed senior reactor operator will be in the main a. control room area at all times when the unit is in j operational Condition 1, 2, or 3. b. A licensed' reactor operator will be in the main control room at all times whenever there is fuel in the reactor. c. The licensed senior reactor operator assigned to supervise core alterations in Condition 5 may have no concurrent operational duties. d. If the Nuclear Shift Supervisor (NSS) position is not filled by an STA/SRO, a qualified shift technical ~ advisor is required in operational Conditions 1, 2, and. 4 3. e e. In addition to the Radiation Protection Technician required to be on shift whenever there is fue1~in the reactor, all shift personnel will be trained in basic radiation protection. 1 f. Shift hours will be administrative 1y controlled to ensure compliance with current NRC policy. 13.1.3 OUALIFICATION OF NUCLEAR PLANT PERSONNEL 13.1.3.1 Oualification Requirements The qualification requirements for the onsite plant personnel are in accordance with Regulatory Guide 1.8 and ANSI /ANS 3.1-1981. The education, experience, and training requirements of the plant personnel meet the criteria of Section 4 of ANSI /ANS 3.1.-*

-~ 3' 5tirr of initin: car; In= n Table 13.1-3 relates the plant staff positions to the corresponding positions of ANSI /ANS 3.1.

The General Manager may authorize deviations from a qualification l requirement for subordinate positions when the combined education, experience, and managerial competency of an individual is judged' sufficient to ensure adequate performance of designated ~ responsibilities. Such judgement will be documented in writing 1 ~ ( and will not be used to degrade the staff overall qualification. l l 13.1-35 Amendment 13 l

oO HCGS FSAR 11/85 l ) ,x TABLE 13.1-3 (cont) Page 2 of 3 Hope Creek Operations Staff Position ANSI /ANS-3.1 Equivalent-l Senior Operating Technical Supervisor not requiring Supervisor license Senior Operating Support Supervisor not requiring Supervisor license Senior Reactor. Supervisor Reactor engineering l Senior Staff Maintenance Supervisor not requiring license l Supervisor l I&C technician Technician l Senior Nuclear Maintenance Supervisor not requiring license l-1 Supervisor l Nuclear Maintenance Supervisor Supervisor not requiring license l \\' Electrician Maintenance personnel l Machinists Maintenance personnel Boiler repair mechanic Maintenance personnel Station mechanic Maintenance personnel Senior Radiation Protection Supervisor not requiring i Supervisor license (*) Senior Radiological Engineer Supervisor not requiring l license (*) Radiation Protection Supervisor Supervisor not requiring license l l Radiation protection technician Technician Radiation protection assistant i Senior Chemistry Supervisor Supervisor not requiring license l Senior Chemistry Staff Engineer Supervisor not requiring license l -Q Chemistry Supervisor Supervisor not requiring license l Chemistry technician Technician 7 H+stit9hulcs-SrArn 5tsim Sin;sedit acrr amatuReds ucassel Amendment 13 l l ' ~.. - -

- - =~ - - : ---===: :

-.~-

BE StPPLED HCGS FSAR 1/86 l

r A idler DAW TABLE 13.1-4 (cont)

Page 28 of 123 l TECHNICAL ENGINEER 9 \\NAME; Thomas G. Busch LIC NSES AND CERTIFICATES: Senior eactor Operator License - Wm. H. Zimmer Nuclear P er Station OP-10096 Certified ineer in Training - State of Ohio EDUCATION AND T INING: 1975 Bachelor of Science in Nu ear Engineering, 975, University pf Cinc'nnati, Cincinnati,

y__,

1976 Succ.ssfully comple >d a four week course of classr om and labo atory training dealing with op ation o Honeywell 4000 series process c mpute s. During the course process assembly 1 g ge was learned along with operation an interfacing of the computer operating e s m and other software. The course wa con cted by Honeywell. 1976 Succes ully comp ted a five week course of clase com training neerning thermal hyd aulic and nuclea characteristics of BWR c es of an engineerin level. Thermal limit Iculations and bases, ore flow calibration, fuel precond tioning and process computer software were lea ed along with reactor integrated response o control changes. The course was cond ted by the General Electric Company. 1976 Successfully completed a three wee course consisting of classroom and laborat y training dealing with the BWR process computer NSSS software package. The m hods employed in calculating core power distribution and thermal limits was learn The course was conducted by The General Electric Company. Amendment 14 l

HCGS FSAR 1/86 l / TABLE 13.1-4 (cont) p/ Page 29 of 123 l 1977 Successfully completed an intensive twelve week course dealing with systems and operation of a BWR (Browns Ferry Unit 1) including approximately six weeks of simulator training, ultimately leading t SRO certification. The course was conducte by the Genera.1 Physics Corporation at th TVA Power Production Training Center, Chattanooga, TN 1977 Completed a four week course co isting of approximately eighty hour of c ssroom review and eighty hours of observati of all facets of BWR operation. The cour was conducted by the General Physics Cor ration at the owns Ferry Nuclear Pow Station. 1978 Wor ed approximately t o months during the peri 6/78 to 11/78 t the Edwin I. Hatch Nuclea Power Plant Served as shift test enginee during i tial fuel loading. Particip ed in w power testing to .( approximat ly 3. power on Unit No. 2. 1980 During the p iod 2/24/80 to 3/15/80 worked with the N le Engineering staff of the Monticell Nucl r Generating Station during the core alterati s, control rod drive mainte nce and fu shuffling periods. 1980 Dur g the period 3/3 80 to 4/9/80 worked wi the Nuclear Engin ring staff of the nticello Nuclear Gener ting Plant during he plant startup followi refueling to full power. 1980 Electrical Engineering Techno gy, twelve credit hours, Clermont Technica

College, Batavia, Ohio 1981 Successfully completed a six day si lator course for Shift Technical Advisors c nducted by General Electric at the Morris simu tor.

1981 During the period of 3/21/81 to 3/15/81 participated in NRC evaluation of emergenc operating procedures developed from BWROG guidelines and contingencies. Review Amendment 14 l

HCGS FSAR 1/86 l r TABLE 13.1-4 (cont) Page 30 of 123 l conducted by NRC Proced'ures Testing Review Branch at the Morris simulator. 1981 Shift Technical Advisor Program, eighteen graduate credit hours, University of Cincinnati, Cincinnati, io 1983 During the period of 1/6/83 to 3/11/ 3 participated in the reactor engine ing activities at the Susquehanna Ste m Electric Station. During that time SSES nit I was undergoing power escalation te ing from 30 to 100% power. 1983 NPO Technical Managers Wo shop EXPERIENCE: Public ervice Elec ic and Gas Company Hope Cr k Generat ng Station 1984 - Present Technical gin er responsible for program development conduct of activities in the areas of rea or engineering, technical reports and pr edures, thermal performance, equipment ella 'lity monitoring and testing, and docu nt cont 1. Cinci ati Gas and ectric Company Wm. Zimmer Nuclear ower Station 1983 - 1984 S ved as Superintendent of the Technical uppor_t Division. Respon ble for supervision of eight staff ngineers and four engineers in training. Tech ical Support Division activities include: eactor engineering, computer engineer 1 g, coordination of preventive maint ance and surveillance testing programs, de lopment of WPRD databases, and providing tech ' cal support to other departmental divisi s. 1981 - 983 Served as Technical Engineer, responsib e for supervision of five engineers assigned t the reactor engineering and computer engineert g groups. Also during this period, coordinat d development of preventive maintenance and s surveillance test scheduling, equipment Amendment 14 l

i i 1 HCGS FSAR-1/86 l. ? TABLE 13.1-4 (cont) Page 31 of 123 l nameplate database,' spare parts inventory, and commitment tracking computer based systems. Was also responsible for traini of personnel and conducting drills for e. Technical Support Center staff in pre ration for a successfully completed emerge y i preparedness exercise. 'l 1977 - 1981 Served as Reactor Engineer, re onsible for preparation of core alterati fuel handling, SNM accountabili core thermal 'mit surveillance, neut n monitoring i eq ment calibration d other station proc ures. Primari responsible for receip of the ini al core fuel. Assisted the Star p Coor nator with preparation of administra ve ontrols, test implementing procedures a licensing submittals for the startup te in program. Assisted the plant Technical ngine in preparation of plant Technic Specific ions. ( 1975 - 1977 Ser d as Staff Engine r in the Technical i S port Division. Prep ed, reviewed and onducted system flushing nd preoperational i test procedures. 1972 - 1975 Served as Student Engineer in t ining at the Walter C. Beckjord station, a six nit pulverized coal generating plant. ring this period worked in the maintenance, 1 operations and technical staft departme s on an alternating quarterly basis as part o he l University of Cincinnati co-op student program. i i i Amendment 14 l

HCGS FSAR 1/86 l I 1 TABLE 13.1-4 (cont) Page 80 of 123 l NUCLEAR SHIFT SUPERVISOR IREDDLEk \\ NAME: Charles Randle - ) MILITARY RECORD: 8/64 - 8/68 U.S.A.F. Hon. Disch. E-4 Aeromedical Evacuation - 2 years in Vietnam EDUCATION: Academic Diploma from Jeff Davis High School, Hazlehurst, GA s Georgia Southern College, Statesboro, GA 2 years credit toward BS in Biology. Nuclear Power Plant Operator Training '18 1 months Nuclear Theory, BWR Technology, BOP System 4 Analysis, Transient Analysis, System to System Interface, Browns Ferry Simulater, NRC Certified. l EXPERIENCE i 1984 - Present Public Service Electric and Gas - Hope Creek j Generating Station - Nuclear Shift Supervisor. ) ) 5/1983 - 1984 Plant Operator, Georgia Power Company's i E. Hatch Plant - Reported directly to Shift Supervisor and have as a minimum, the following responsibilities and authorities: a. Responsible for operation and refueling in a safe manner under the direction of the Shift Supervisor. 4 l b. Aids plant management and his immediate supervisors in cartying out the saf e, reliable and efficient fuel loading, / operation and maintenance of the plant. Amendment 14 l

IM W W y ygg y, gty HCGS FSAR 1/86 l l' TABLE 13'.1-4 (cont) Page 114 of 123 l SENIOR TECHNICAL SUPERVISOR P ~'NAME : Elmer J. Galbraith LICEN S AND CERTIFICATES: U.S. Nav Qualification for Operation, Maintenance and Supervisio of Naval Nuclear Propulsion Plants l' EDUCATION NayelhSEssemy-Annapol MD 1957 - 1961 U.S. (Engineering) 1961 U.S. Naval Submarine Sc ol 1964 U.S. Na 1 Nuclear P er School [, 1965 U.S. Naval ucle Propulsion Prototype Training 's 1973 U.S. Navy Pos don Command Training 1976 U.S. Naval uclea Propulsion Plant Prospective Commandi Officer raining 1976 Subma ine Prospective mmanding Officer Tra ing EXPERIENCE: 1984 - Present Senior Technical Supervisor - Ho Creek Generating Station Public Service lectric & Gas Co. Responsible for program development an conduct of activities in the areas of technical specifications, technical docume t control, reporting requirements, surveillances, operating experience review and procedures. Ng Amendment 14 l

INSERT FOR TABLE 13.1-4, PAGE~114 OF 123 i SENIOR TECHNICAL SUPERVISOR NAME: William J. Merritt LICENSING AND CERTIFICATES: 4 Engineer-in-Training (EIT), New Jersey 1 EDUCATION: i 1976-1977 New Jersey Institute of Technology 1 1978-1980 Rensselaer Polytechnic Institute (BSME-1980) I 1983-Date Temple University Law School EXPERIENCE: i 1985-Present Senior Technical Supervisor - Hope Creek Generating Station, Public Service j Electric and Gas Company. Responsible for program development and conduct of activities in the areas of technical specifications, technical document control, reporting requirements, i surveillances, operating experience review and procedures. 1982-1985 Staff Engineer - Hope Creek Operations Operations Department i Procedure Coordinator - Responsible for assuring that all procedures required to support fuel load are in place in j a timely manner. This involves developing procedure guidelines consistent with regulatory requirements, coordinating 4' the writing efforts of contract personnel, reviewing the various procedures, and interfacing with plant safety review l groups. 4 1 i

INSERT FOR TABLE 13.1-4, PAGE ll4a OF 123 Technical Specification Reviewer - Responsible for the review of Hope Creek Draft Technical Specifications. As the prime reviewer for the Operations Department, this involves a detailed review of the FSAR/SER commitments, research into the plant design, interface with the architect-engineer and NSSS vendors. 1980-1982 Engineer - Stone and Webster Engineering Corporation Integrated Procedure Schedule Developer - Developed an integrated schedule for the development of all operational software (i.e., Operating Procedures, Maintenance Procedures, etc.) at the Nine Mile Point - Unit 2 Nuclear Station. Mechanical System Verifier - Performed preliminary as-built verification walkdowns of mechanical systems at the Oyster Creek Nuclear Station. Utilizing the information gained during the walkdowns, developed manhour estimates for the complete as-built verification program. Final Safety Analysis Reviewer - Reviewed the Nine Mile Point - Unit 2 FSAR against the NRC Standard Review Plan to ensure compliance prior to submittal to the Staff. System Description Writer - Prepared System Descriptions for mechanical and electrical systems at the Nine Mile Plant. Spare Parts Coordinator - Coordinated the identification, evaluation, and procurement of spare parts for the containment isolation valves at the Oyster Creek Nuclear Station.

HCGS FSAR 1/86 l TABLE 13.1-4 (cont) Page 115 of 123 l 1984 Acting Plant Manager for WNP-3, Washington Public Power Supply System With project in extended construction de y responsible for preservation of assets, preparation of operating procedures an support for licensing and engineerin. Supervised EM) people in this effort Maintained position as Technical & Startup Manager with a minimal activity artup effort. 1982 - 1984 Technical and Startup Manage for WNP-3, Washington Public Power Sup ly System.- Technical Manager, re onsible for setting u departmen.t consisti of 25 plant eng eers to report d ectly to the Plant Mana r for plant su port and performance. As Sta tup Manager esponsible for startup of Combust n Engine ing 1240 megawatt pressuri d wat reactor. Supervised and ( supported tar p contractor in this effort. 1981 - 1982 Plant Manag nt Training Program, Washington Public Pow S ply System Partici ted in t ining program designed to meld n val nuclear ropulsion experience with curr t nuclear util'ty practice and ope ations and meet t requirements of ANS 3. for plant managemen positions. The ogram consisted of: Assignments to all pro'ect departments including construction, esign i engineering, quality ass ance and licensing for a period of x months. Plant training for six months at Southern California Edison's S Onofre i nuclear generating station. As 'gned to the Station Operations and Techni 1 Managers for various periods as pa of their working staffs. Participated the startup effort of the Unit 2 Combustion Engineering Pressurized Wate i Reactor. i Amendment 14 l ~. _ _ _

HCGS FSAR 1/86 l l' t' TABLE 13.1-4 (cont) .Page 116 of 123 l 979 - 1981 Tactics Training Department Director, FBM Submarine Training Center, Charleston, S.C. Responsible for operation, repair and maintenance of six major submarines trai ng devices (Tactical, ship control and son ). Supervised approximately 70 personnel n this effort. Conducted liaison between v ious contractor and government agencies the installation and operation of the trainers. Involved in curriculum developme 1976 - 1979 Commanding Officer U.S.S. Ray SSN653) uclear powered attack sub rine based in rleston, South Carolin with crew of 12 of cers and 100 enliste personnel. Duties enco. assed complete s' ctrum of submarine opera ons including .11pyard period and extende deployment perating at sea for several nths wit ut a logistic support

base, i

1973 - 1976 Executive Of er - U.S.S. Stonewall Jackson (SSBN634) Fleet ball stic ssile submarine operating out of H y Loch, cotland, conducting strateg'c deterrent atrols. As second in comma was responsi e for the ship's oper ion and crew tra ning and management. Sup rvised the movement f 120 crewmen from i t off-crew training sit, New London, CT. o the deployed site (Scot nd) and back upon i completion of the patrol. is cycle was repeated every six months. 1971 - 1973 Navigator, Main Propulsion Assi ant, Weapons Officer - U.S.S. GATO (SSN615) Held department head level position, as listed, at various times aboard this clear powered attack submarine based in New

ndon, Connecticut, Duties included at sea operations, pre-overhaul testing, 15 mont shipyard overhaul at Ingalls Shipbuilding Corporation, Pascagoula, Miss. and post shipyard refresher training.

During overhaul was extensively involved in the repairs and Amendment 14 l

HCGS FSAR 1/86 l ? TABLE 13.1-4 (cont) Page 117 of 123 l subsequent restart and testing of the reactor plant. While aboard completed certification as Engineer Officer by the Director, Divisi n of Naval Reactors, U.S. Department of Ene y. 1969 - 71 Company Officer U.S. Naval Academy, Annapolis, MD. Supervised 100 midshipmen, monit ed academic, physical and militar training; conducted counseling; taught eadership; ' handled liaison between dshipmen/ parents /congre s. 1965 - 1969 Navi tor, Main Propu ion Assistant, Weapons Offic Training O icer, U.S.S. QUEENFISH (SSN651 Held depart en head level positions listed at various t es aboard this first of a new cl'ss nucl r wered attack submarine based a in Pearl

arbor, awaii.

Duties included ( constru ion and i tial startup testing at \\- the b Iding shipya Newport News Shi uilding and Dryd k Company, Newport N s, Virginia. Upon c.pletion, ship ransferred to the Pacifi fleet where shakedown training and oper tions preceeded extended deployments at sea. 1962 - 1964 Engineer, Gunnery Officer, Suppl Officer U.S.S. BARRACUDA (SST-3) Held department head level positions sted at various times aboard this diesel-ele ric submarine based in Key West, Florida. Du ies included two extended shipyard periods including pre-and post-overhaul testing and local and deployed at-sea operations. (. Amendment 14 l l

i + MAINTENANCE ENGINEER 1 + + + SENIOR SENIOR SENIOR MAINTENANCE MAINTENANCE MAINTENANCE SUPERVISOR SUPERVISOR SUPERVISOR MECHANICAL 1 BOILER REPAIR j E LECTRICAL j + + + MAINTENANCE MAINTENANCE MAINTENANCE SUPERVISO R SUPERVISOR SUPERVISOR MECHANICAL BOILER REPAIRS ^ 2 S 3 e + + + MACHINIST REPAl MAN ELECTRICIAN 10 10 16 1 + ftTttiTW-y CUSTODIAN STATION SuTERl/lSoQ )g ' MECHANIC 16 N 18' OLSTODfAUS HECMMIC E LEGEND: + POSITION REQUIRED TO MEET ANSI /ANS 3.1 I

+ MAINTENANCE MANAGER 1 C + I&C ENGINEER 1 / + + + SENIOR SENIOR ,/ SENIOR SEN ;O r'/ AINTENANCE MAINTENANCE STAFF _gy){ d y[.7"7-n ^ = >. 7 SUPERVISOR iUPE RVISO R SUPERVISOR 0. l&C l&C 3 1 3 3 \\ + + + + 7 AINTENANCE MAINTENANCE ^T AC / STAFF [LANNE,\\ 7 iUPERVISO R SUPE RVISO R OA1 ENGINEER I&C I&C 3 3 / 4 i + + 8 ECHNI IANS TECHNICIANS CLER! CAL CLERICAL 13 13 1 7 Y I&C ASSISTANT / WORKER 8 HOPE CREEK GENER ATING STATION FINAL SAFETY ANALYSIS REPORT MAINTENANCE DEPARTMENT HOPE CREEK OPER ATIONS FIGURE 13.1 11 Amendment 13,11/85

\\ HCGS FSAR 01/85 13.2.1.1.1 Cold License Training Program This program is designed for NRC reactor operator (RO) and senior reactor operator (SRO) cold license candidates of varying backgrounds and experience. Candidates will be factored into the program at various points, depending on their previous experience and training. Testing and screening will be an intimate part of NAts the overallitraining program. All license candidates who are AR9CSD supervisors'T ::: ottrnc the PSE&G Technical Supervisory Skills Program and IEE*3tmeet the supervisory training requirements of -ANSI /ANS-3.I'-1981, Section 5.2.1.8.p ine r ccer : nn e3 To assure the experience criteria of ANS 3.1 (1981) is met, as well as the general guidelines of NUREG-0094, additional experience will be provided by a structured observation program for all licensed operator candidates. A detailed description of this observation training is shown in Appendix 13K. 13.2.1.1.1.1 Senior Reactor Operator Training Program The senior reactor operator (SRO) candidates will attend a training program consisting of, but not limited to, the following areas of instruction: a. Nuclear Reactor Fundamentals b. Reactor Startup Experience c. Advanced technical training d. Pre-Certification system training e. BWR Cold certification training f. In-plant training g. Hope Creek Systems training h. Pre-license examination testing and training i 13.2-3 Amendment 9 k e i

. -.. = _ _. __ - - i i HCGS FSAR 01/86 (- t i 14.2.12.2 General Discussion of Startup Tests i' All tests associated with the startup test phase are discussed in Section-14.2.12.3. For each test, a summary is presented defining the test objective, prerequisites, test method, and acceptance criteria. Test objectives identify those operating and safety-related characteristics of the plant that are involved ll in the test. I The operating power-flow map is presented as Figure 14.2-4. The-test conditions are marked on Figure 14.2-4, and each test described in Section 14.2.12.3 is accomplished at the test conditions stated in Figure 14.2-5. These two figures represent the startup test schedule. The testing sequence generally runs from test condition 1 through test condition 6, with the i exception that test condition 4 (natural circulation) is normally - performed subsequent to the testing in test conditio [ The startup test acceptance criteria are developed and approved j by the design group organizations. In developing specific test acceptance criteria, the design groups will reference material -j( such as: l a. FSAR Chapter 16, Technical Specifications b. FSAR Chapter 15, Accident Analysis I c. Other FSAR sections i d. Vendor topical reports { e. Vendor technical documents f. Design specifications ~ 4 g. General Electric startup test specification. i i The specific acceptance criteria will be listed in each startup l test procedure. The criteria section of each test procedure has { up to two sections, which are discussed below: \\ i' p. i l j 14.2-152a Amendment 14 i I (_ Q. j w -a e-+ w,* 77. _ ],, w

...w-HCGS FSAR 10/84 l OUESTION 430.80 (SECTION 9.5.4) In Section 9.5.4.2.1 you discuss the corrosion protection both internal and external for the fuel oil storage tank. No discussion is provided on the corrosion protection provided for the fuel oil fill piping. Expand the FSAR to include a more explicit description of proposed protection of underground piping. Where corrosion protective coatings are being considered (piping and tanks) include the industry standards which will be used in their application. Also discuss what provisions will be made in the design of the fuel oil storage and transfer system in the use of a impressed current type cathodic protection system, in addition to water proof protective coatings, to minimize corrosion of burried piping or equipment. If cathodic protection is not being considered, provide your justification. (SRP 9.5.4, Part II)

RESPONSE

The diesel fuel oil transfer piping that is buried is primed and wrapped, in accordance with industry standards, AWWA-C-203 including Appendix A1.5 and/or A2.0. The buried portions of the diesel fuel oil transfer piping are cathodically protected by an impressed current cathodic protection system. The impressed current cathodic protection system is also considered as a nonsafety-related system. The diesel engine fuel oil transfer piping cathodic protection system will be tested and inspected per Maintenance Department preventive maintenance _ procedure MD-PM-OH-001 (0) Cathodic Protection System P.M. tad th; Technical C;;cific;ti;ns The frequency and type of below: reventive maintenance activities are shown 2 Months l Rectifier unit will be visually inspected for physical damage and excessive heat. Output voltage and amperage will be recorded. (Adjustments made as needed). The interior and exterior of the unit will also be cleaned at this time. 12 Months l 1. The anode test leads will be cleaned and verified to be adequately protected. 2. Performance test of underground portion of system to determine if protection is adequate. The buried portion of the diesel fuel oil transfer piping is not considered safety-related piping since an emergency fill 430.80-1 Amendment 8 l >}}

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