ML20244D013
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NUCLEAR REUE TORTCOMMISSION ADVISORY COMMITTEE ON REACTOR SAFEGUARDS s
C?ASHINGT ON, D. C. 20555
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July 17,1984 Honorable ilunzio J. Palladino Chairman U.S. huclear Regulatory Commission Washington, D.C.
20555
Dear Dr. Palladino:
SUBJECT:
ACRS IliTERIM REPORT ON RIVER BEhD STATION 32-14, 1984, the Advisory Committee on During its '491st nieeting, July Reactor Safeguards revieweo the application of Gulf States Utilities Company (Applicant), acting on behalf of itself and as agent for the Cajun Electric Power Cooperative, for a license to operate the River A tour of the f acilities was made by menibers of the Send Station.
Subcornittee on the morning of June 7,1984, and a Subcommittee meeting was held in Baton Rouge, Louisiana on June 7 and 6, 1984 to consider the During our review, we had the benefit of disc'ussions with appli cat. ion.
the NRC Staff, and members of the representatives 'of the Applicant, of the documents referenced.
The public.
We also had the benefit the construction permit application for this Comraittee corraented on Station in its report dated January 14, 1975.
The River Bend Station is located irt West Feliciana Parish, Louisiana on the east side of the Mississippi River approximately 24 miles north-OriS nally the River Bend Station was to i
Unit 1 northwest of Baton Rouge.
Unit 2 was cancelleo on January 5,1984.
consist of two units.
is approximately 901 ccmplete, with an estimated fuel. load date of April 1985.
The~ River Bend Station uses a General Electric BWR-6 nuclear steam supply system (NSSS) with a rated core thennal power of 2894 MWt and a Mark III pressure suppression containment system with a design pressure of Ib psig.
has structured its organization, and has provided for The Applichnt continuity from project initiation up to and including operation, in ateam lines an notable manner.
This structuring is along project appears to have provided good control and interfacing among the utility, the general contractor-architect engineer, and the NSSS designer.
Further, it appears this structuring has provided this first time nuc-lear utility with scod personnel development for the utility's overall nuclear plant responsibilities.
In additier. to this, the
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y-1 Honorable hunzio J. Palladino July 17, 1984
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Applicant has practiced asgressive recruiting and careful selection of
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qualified people anc has phased them into the project in a timely l
manner.
The dedicated diesel generator that drives the high pressure core spray pump currently depends on cooling water supplied by pumps powered by the We other two diesel generators during loss of offsite power conditions.
recomend that the merit of removing this dependency be examined.
l The Applicant stated that they plan to ' conduct a limited probabilistic risk assessment (pHA) for the River Bend Station.
We support the i
l propcsal to perform a plant-specific PRA and reconn.end that it include seismic-and fire-induced accident scenarios.
Although River Bend is in a relatively quiet seismic portion of the NRC contractor estimates of the recurrence interval for the cou ntry,
safe shutcown earthquake are similar to those for most eastern sites.
We recomend that the Applicant review, in detail, the seismic capability of.the emergency AC power supplies, the DC power supplies, anc staall components such as actuators, relays, and instrument lines that are part of the decay heat removal system.
The Applicent has proposed to include in the River Bend Emergency Procedures a procedure for venting the containment under certain i
The bases for the decision to take this action are accident conditions.
The NRC Staff ha's, not completed its review of this not yet clear.
proposal.
We wish to be advised when the NRC Staff has reached a position on this matter and to have an opportunity to coment generically or specifically.
The NRC Staf f has identified a number of license conditions and con-firmatory matters, and several outstanding issues which remain to be resolved.
Except for the matter of hydrogen control, we are satisfied they should be with progress on the other topics and believe that resc1ved in a manner satisfactory to the NRC Staff.
We have not completed our review of hydrogen control for the River Bend Station, particularly as it may be impacted by differences in containment design features between River Bend and Mark III BWRs previously reviewed.
The Corxt.ittee will cortplete its review of the full power operating license when the hhc Staff and the Applicant have made sufficient In the additional progress in resolving the matter of hydrogen control.
interim, we believe that if due consideration is given to the recom-mendations above, and subject to satisfactory completion of construc-tion,, staffing, and preoperational testing, the River Bend Station can
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. Hoiorable Nunzio J. Palladino l
be o erated at power levels up to 5% of full power without undue riskto J
the ealth and safety of the public.
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Jesse C. Ebersole Chairtnan I
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References:
Guit $tates Utilities Company, " Final Safety Analysis Report, River i
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Bend Station," Volumes 1-18 and Amendments 1-11 i
U. S. Nuclear Regulatory Commission, " Safety Evaluation Report 1
Related to the Operation of River Bend Station," NUREG-0989, dated 2.
May 1984 t
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1 CULF STATES UTILITIES COMPANY Post orricenomies,. saavuo%1 iaxas,,,o.
A a t a c o ti c 4 e e e a s. e e s,
August 26,1985 RBG-21924 File Nos. G9.5 Mr. H.R.
Denton, Director Office of Nuclear Reactor Regulation U.S. Nucicar Regulatory Comission Washington, D.C.
20555 Dear Mr. Denton River Bend Station Unit 1 Docket No. 50-458
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On January 15,1985, Gulf States Utilities (GSU) submitted an interim response to ten iter.s identified by members of the Advisory Co:::nittee on Reacter Safeguards (ACRS) during the full committee ACRS meeting held on July 12,1984.
Please find attached GUS's updated positions with respect to each of these items, Sincerely, I
J.E. Booker Manager - Engineering Nuclear Fuels & Licensing River Bend Nuclear Group JEB/BEH/ko Attachment
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.ATTACMMENT I
Item No. 1 The dedicated diesel generator that drives the high. pressure core spray (HPCS) pump currently depends on cooling. Vater supplied by pumps powered by the other two' diesel generators during loss of offsite power conditions.
The ACRS recomends that the merit of removing this dependency be examined.
I GSU_ Position GSU has examined the merit of a completely independent HPC supply.(Standby Service Water (SSW) pumps powered by sither the Division I or II diesels) met NRC Staff regulatory requirements and was the same design as The concern expressed by the ACRS involves reviewed at the CP stage.
failure of both Division I and II diesels to operate (i.e. multiple For this f ailures which is beyond current NRC design requirements).
postulated case, the HPCS diesel (Division III) would be denied cooling water and would not be operable.
j To remove this dependency a design modification was undertaken which f
involved off loading one of four SSW pump motors, its associated discharge valve and pump cubicle cooling f an from the Division I diesel generator and In addition, Division III adding this load to the HPCS diesel generator.
SSW initiation instrumentation was added and associated instrument control hardware changes were cade.
This design change vill allow 50% of the long term (i.e. Post RHR shutdown cooling initiation) SSW cooling water to be provided from the Division I diesel while the other 50% vill be provided frer. the HPCS diesel generator.
Division II remains unaltered and capable of supplying 100% of the required j
Single failure criterion for the diesels is
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long term SSW cooling water.
satisfied in the following manner:
Loss of either the Division I or EPCS Division III diesels - 100:
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SSW cooling water supplied by Division II diesel, Loss of the Division II diesel - 100% SSW cooling is supplied (50:
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from Division I and 50% from the HPCS Division III).
This GSU notified the NRC staff of the HPCS modification via PSAR changes.
information was forwarded to the NRC via letter RBG-19576 dated 11 and was included in FSAR Amendoent No. 16.
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Item No. 2 GSU stated that they plan to conduct a limited probabilistic risk assessment (FRA) for the River Bend Station (RBS). The ACRS supports the proposal to perform a plant-specific PRA and recom= ends that it include seismic-and-fire-induced accident scenarios.
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GSU Position GSU is one of forty-two utilities participating in the " Seismicity owner's Group" study entitled " Seismic Hazard Methodology for Eastern U.S.A." RBS is one of the nine reactor sites selected for co=putation pertaining to The RBS site is located in an area of low seismicity, well earthquakes.
above the Mississippi River flood plain, over 100 miles from the nearest seacoast, and in an area of lov er at most, average tornado activity.
Preliminary figures and estimates indicate that the likelihood of,gnto 10 3 earthquake exceeding the design basis would be on the order of 10 This is an order of magnitude or two lower than that anticipated per year.
for many sites....Since the frequency of occurrence of these events is extremely low and.because of the extreme severity needed to generate major accidents from these initiators, omission of earthquakes as an external event is justified.
A study comparing fire induced accidents at RBS with the standard BVR-6 was conducted by the General Electric Company for CSU. The analysis was performed on the basis of fire protection ressures described in FSAR Section 9.5.1, " Fire Protection System" and Appendix 9A, " Fire Protection Program Evaluation Report." The event and fault trees of the GESSAR II Nuclear Island Plant PRA were used to assess the impact of a particular fire in the plant systems and to estimate the core damage frequency initiated by the fire.
RBS meets NRC staff fire protection requirements, co. pares f avorably with GESSAR II, and is significantly better than other PRA for plants of similar It is concluded that fire need not be considered further in PRA design.
analysis.
I In conclusion, CSU has performed Phase-2 of a limited PRA anayisis of RBS.
I Phase-2 was based on Grand Gulf-l event trees supplemented by RBS plant trees and site specific consequence analysis.
In addition, specific fault fire induced accident. scenarios were. considered-and.RBS_vas. compared.wi,th_.
t GESSAR-II and operating nuclear plants.
Results of the limited PRA l
analyses, when compared to more detailed PRA's for other plants of similar design, indicate that the impact of internal and external initiating events can be predicted adequately and that additional PRA analysis is not warranted.
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Item _No._ $_
Although River Bend is in a relatively quiet seismic portion of the country, j
NRC contractor estimates of the recurrence interval for the safe shutdown The ACRS recommends carthquake are similar to those for most eastern sites.
that GSU review, in detail, the seismic capability of the emergency AC power supplies, the DC power supplies, and small components such as actuators, relays, and instrument lines that are part of the decay heat removal system, i
GSU Position G50 has completed an investigation of the equipment, instruments and supports for seismic capability.
Of the 141 pieces /17 types of equipment in the decay heat removal system, 21 pieces /8 types of equipment were sampled to determine each piece's seismic
' Evaluation..of calculational methodology including random sampling margin.
of actual support seismic margins were also conducted for instrument stands, instrument tube supports, cable tray supports and small bore pipe supports The within the decay heat removal system and the AC and DC power supplies.
of that required to tinimum margin of safety (i.e., seismic margin in excess meet our licensed.lg design basis ground acceleration) was 250%.
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GSU believes the exhibited margins of safety are representative of the total population and that these =argins are typical of the overall design.
This review demonstrates the conservatism that exist in the seismic The conservatism provide adequate justification of equipment and supports.
assurance that the equipment and supporting structures will survive and remain functional during a seismic event.
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Item No. 4 River Bend employs refrigerated charcoal beds in the offgas processing The ACRS requests that GSU provide an system for the main condenser.
estimate of the off aite doses given the complete loss of refrigeration to the beds and the failure to manually isolate the offgas system from the main plant exhaust.
GSU Po_sition The calculated dose rates due to continuous noble gas releases from the main plant exhauce increase by a factor of approximately rwo due to loss of This assumes all other plant refrigeration to the charcoal beds.If refrigeration were lost for one ponth, the parameters remain constant. Restricted Area Boundary dose from noble gases would dose in air) and 0.1 mrad (beta dose in air).
mrad (gam =4 Based on a comparison of these estimates to 10CFR50 Appendix I design objectives, we feel that a loss of refrigeration to the charcoal beds will not presant any off-site radiological hazard.
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Itam No. 5 River Bend Station. containment personnel and equipnent hatches utilize The ACRS expressed interest in: (1) length of time inflatable seals.
accumulators would be able to maintain air pressure to the seal in a post-cccident. situation given a specified leakage frem the seals, and (2) reocu-ery plans shculd one lose air pressure to the seals in a post-accident situation.
Gs0 Position The only contairnent vessel hatches at RBS utilizing inflatable seals are GSU has examined the personnel' air lock the personnel air lock hatches. inflatable seal design with respect to mainten pressure to the seals in a post-accident situation.
The air lock is designed to hold the seal inflation pressure for a period of 35 days via an inSerendent Category I auxiliary air supply self-me loss contained within each door, in no way jeopardizes containment integrity for a period of 35 days.
mt data taken on the subject air lock seals indicate that air losses fecm i it, required the air lock seal system is less than half of the tech spee l m 1
to maintain integrity of the air locks for 35 days.
l Investigation of the air lines and isolation valves supplying the inflata-ble seals (two on each door) indicates that in the event of a loss of supply air during a post-accident situation an alternate air supply could be tied into the existing supply lines just outside the outer containment This altemate air supply could be a supply of bottled air or a portable ccr pressor either of which could be installed in short tire (1-2) air lock.
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f tem No. _6 The ACRS requests that it be provided the qualification program and data for River Bend's containment isolation valves for the 36 inch diameter containment purge and vent lines.
CSU Position The valves in question are identified as follows:
LOCATION /FLTNCTION MARK NLH_BER Supply Line Inboard CIV 1HVR*A0V123 Exahust Line Inboard C1V IHVR*AOV128 Supply 31ne Outboard CIV 1HVE*A0V165 Exhaust Line Outboard CIV IHVR*A0V166 The valves are 36 inch diameter high performance butterfly valves with air cylinder actuators manufactured by Posi-Seal International, Inc. (PSI).
VELD END VALVE.
Each valve is designated by PSI as a 36" CLASS 150/150 Each valve is furnished with a MATRYX fail-closed air cylinder actuator, or Model No. 45122-SR80 (A0V165,166).
Model No. 33122-SRSO (A0V123,128)
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GSU has specifically addressed the issue of qualification of these valves in our response to the NRC Staf f's Branch Technical Position (BTP) 6-4 (reference letter RBG-19,385 dated November 8,1984) with regard to the Dryvell/ Containment Purge System.
The 36 inch diameter containment isolation valves in the Contain=ent Purge System are qualified to perform their intended function, including full closure upon the initiation of a co=bined LOCA and DBA seismic event.
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Item No. 7 In the phase II work on the River Bend PRA, GSU plans to modify their PRA l
to include design consideration for ATWS.
The ACRS requeste that G5U provide their estimate of the failure rate for the recirculation pump trip logic.
It is suggested that the results of the phase II PRA program be provided to the Co=mittee.
CSU Position ThefailurerateoftheATW5Recircu1AtgonPumpTrip(RPT)usedinthe Stone and Webster analysis is 3.8 x 10~ per reactor year.
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cotepares f avorably with the General Electric value of 6.3 x 10~g value per demand.
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Item No. 8 Unit coolers are to be used at RBS instead of containment sprays to control temperature and pressure following an accident.
Containment sprays have previously been cited as being very efficient in the removal of airborne radioiodine.
To what degree can a unit cooler system be expected to remove airborne radioiodine or other materials?
C_SU_ Position The River Bend containment unit coolers remove airborne fission products by the same eethod as containment sprays, that is, by condensation. The River Bend unit coolers are designed to condense 1007. of the steam that bypass the suppression pool, assuming no surface condensation.
The actual capability of the unit cooler to remove airborne fission products has not been assessed. This assessment is not necessary since the impact on further reducing the amount of fission products released would be minimal due to the effectiveness of pool scrubbing and condensation of water vapor from"the atmosphere onto containment surfaces.
This is supported by a UE performed analysis which considers postulated severe accidents with pool bypass, in which the bypass steam is condensed either on contain=ent surfaces or by the unit cooler, and shows that this event
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would have negligible overall risk. Additionally, following the guideline of Regulatory Guide 1.3, River Bend LOCA analysis assumes that 50% of the iodine from an equilibrium core is released to primary containment and of this 'elease, 50% of the iodine remains airborne.
The remaining 50% is r
assumed to " plate-out" on centsinment surfaces.
This analysis takes no credit for any fission product rs= oval via condensation through the unit coolers. The resulting calculated exposures are well within 10CFR100 guidelines.
Thus, while inclusion of fission product re= eval by the p,BS unit coolers would reduce the calculated fission product release, the impact on overall, plant risk is minimal.
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Item No. 9 CSU has proposed to include in the River Bend Emergency Procedures a procedure for venting the containment under certain accident conditions.
The bases for the decision to take this action are not yet clear.
The NRC Staff has not completed its review of this proposal.
The ACRS vishes to be advised when the NEC Staff has reached a position on this matter and to have an opportunity to co==ent generically or specifically.
CSU Position l
CSU has analyzed the containment response to the most probable sequence of events that would require decay heat removal through containment venting through presently existing systees.
The transient analyzed will proceed slowly allowing significant operator action.
If attempts to initiate and restore all design capabilities for decay heat recoval are unsuccessful, the ultimate decision to vent vill be made by the Emergency Director and as available, input from the NRC, state and local officials will also be taken into consideration.
Emergency Operating Procedures direct operator actions based on the symptoms and equipment available.
Venting would be initiated through the Hydrogen Purge System or the Containment Ventilation System.
This venting procedure would require opening the containment purge exhaust valves when containment pressure reaches 45 psig. This evaluation agrees with guidance given in the Emergency Procedure Guidelines (EPGs).
The equipment and systems which would be used have been evaluated for their capability to perform as needed.
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Item No. 10 f
The ACRS has not completed its review of hydrogen control for the River Band Station, particularly as it may be impacted by differences in containment design features between River Bend and Mark III BWRs previously reviewed.
The ACRS Will con:plete its review of the full power operating license when the NRC Staff and GSU have made sufficient progress in resolving the matter of hydrogen control.
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G_SU Position In accordance with the requirements of the final hydrogen control rule (10CFR50.44), CSU will have a hydrogen control system, supported by preliminary analysis, installed and operational prior to exceeding 5%
power.
A schedule for demonstrating full compliance with the final hydrogen control rule has been submitted to the NRC (reference. letter RBG-21,389 dated June 26, 1985).
With respect to the final analysis required by the rule, the Hydrogen Control Ovners Group (HCOG) submitted its Hydrogen Control Program Plan to the NRC Staff on December 14, 1984, as an attachment to HGN-024.
CSU, as a member of BCOG,' feels that the approach set forth in the Hydrogen Control Program Plan is a suitable program of research and analysis to demonstrate full compliance with the hydrogen control rule.
This plan is currently under staff review.
GSU will endorse this plan as applicable which will
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serve as an update of the RBS program plan.
As the results of specific HCOG subtasks, activities and reports b'ecome available, GSU will address their individual applicability as necessary.
The final RBS analysis will be completed with schedules consistent with the ECOG program, l
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Table 1.1 Cross-reference table for TMI-2 Action Plan items (revised from SER)
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.HI item Shortened title SER Section I. A.1.1 Shift technical advisor 13.1.4, 13.2.1, 13.2, 13.3.2.2 I.A.2.1.
Immediate upgrade of RO and SRO training and 13.2.1, 13,2 qualification I.A.2.3 Administration of training program 13.1.3 I.A.3.1 Review scope and criteria of licensing exams 13.2.1 I.B.1.2 Independent Safety Engineering Group 13.4.3, 13.1.3 I.C.6 Performance of operating activities 13.5 I.D.1 Control room design review 18, 18.4 2.D.2 Safety parameter display system 18, 18.4~
II.B.4
_Trainin[formitigatingcoredamage 13.2.1, 13.2 ZI.B.9 Analysis of hydrogen control 6.2.5
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.I.D.1 Relief and safety valve position indication 3.10.2.6, 5.4.7 II.E.4.2 Containment isolation dependability 6.2.4.2, 6.2.4.3 II.F.1.1 Noble gas monitor 11.5.4 II.F.1.2 Iodine / particulate sampling 11.5.4 II.F.2 Instrumentation for detection of inadequate 4.4.7, 7.5.2.5 core cooling lI.K.3.27 Common reference level 15.9 II.K.3.28 Qualification of ADS accumulators 5.2.2, 3.10.2.7 81.K.3.31 Plant-specific calculations per 10 CFR 50.46 15.9.4, 6.3.3.3 II.K.3.46 Response to Michelson's concerns 15.9.4 l
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l River Bend SSER 3 1-5
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Table 1.3 Listing of outstanding issues (revised from SER)
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SSER 3 Issue Status
- Section(s)
(1) Hydrostatic loading Closed (SSER 1)
(2) Moderate-energy line break Closed (SSER 3) 3.6.1 (3) High-energy line break Closed (SSER 3) 3.6.1 (4) Inservice test program (including Closed for RCS pressure boundary valve initial license leakage)
(SSER 2)
(5)
Equipment qualification (a) Seismic and dynamic Closed (SSER 3);
3.10.1 qualification see Lic. Cond.12 (b) Environmental qualification Closed (SSER 3);
3.10.2 of equipment see Lic. Cond. 13 (6)
Preservice inspection program Closed (SSER 3) 5.2.4.3, 6.6.3
'. 7 ) Containment loads Closed (SSER 2) l (8)
ECCS LOCA analysis (II.K.3.31)
Closed (SSER 2)
(9) Bypassed and inoperable status Closed (SSER 3);
7.5.2.2 see Lic. Cond. 15 (10) Emergency diesel generators (a) Electrical loads Closed (SSER 3) 8.3.1 (b) Qualification of TDI diesel Closed (SSER 3);
S.3.1 generators see Lic. Cond. 16 (c) Auxiliary support systems Closed (SSER 2)
(11) Submergence of electrical equipment Closed (SSER 2)
Closed (SSER 2)...
(12) Heavy-load handling system
_:.c (13) Safe / alternate shutdown Closed (SSER 3);
9.5.1 see Lic. Cond. 19 (14) Communications systems Closed (SSER 2) l k
(15) Lighting systems Closed (SSER 2)
See footnotes at end of table.
River Bend'SSER 3 1-6 M
Table 1.3 (Continued) i
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SSER 3 i
Issue Status
- Section(s)
(16) HPCS~ diesel generator' Closed (SSER 2) 3 (17) Fuel oil storage Closed (SSER 2) i I
(18) Emergency preparedness closed (SSER 3);
13.3 see Lic. Cond. 11 (19) Separation of electric circuits Closed (SSER 2)
L (20) Human factors issue-(a) Safety parameter display system Closed (SSER 3);
18.1.2.8 see Lic. Cond. 17 (b) Control room survey Closed (SSER 3) 18.1 (c) Resolution.-of HEDs Closed (SSER 3);
18.1 see Lic Cond. 17 (21) Auxiliary systems
- l (a) Standby service water system Closed (SSER 3) 9.2.7 (b) Standby liquid control systems Closed (SSER 3) 4.5, 9.3.5 (c) Low pressure interface leakage Closed (SSER 3) 5.2.5 t(d) Equipment and floor drains Closed (SSER 3) 9.3.3 l-f(e) Control building ventilation Closed (SSER 3) 9.4.1 t(f) Miscellaneous HVAC systems Closed (SSER 3) 9.4.6 (22) Starting voltage for Class 1E Closed (SSER 3) 8.3.1 motors (23) Hydrogen control - degraded core Closed for initial license (SSER 2)**
accident
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- License condition references are numbered as listed in Table 1.5.
- Due to the importance of this item for the full power license, it has been reclassified from Confirmatory Item 19.
TNew issue opened as a result of applicant's FSAR Amendments 20 and 21.
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River Eend SSER 3 1-7 l.
Table 1.4 Listing of confirmatory items (revised from SER)
SSER 3 Issue Status
- Section(s)
(1) West Creek sediment removal Closed (SSER 2)
(2) Ultimate heat sink Closed (SSER 1)
(3)
Slope stability Closed (SSER 2)
(4) Pipe failure modes and check Closed (SSER 3) 3.6.2 valve stress analysis (5)
Annulus pressurization Closed (SSER 2)
(6) Minimum wall thickness Closed (SSER 1)
(7) Thermal and anchor displacement Closed (SSER 2) loads (8) Fuel rod mechanical fracturing Closed (SSER 2)
(9)
Fuel assembly structural damage Closed (SSER 2)
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',10) Postirradiation surveillance Closed (SSER 1) l (11) LOCTVS/ CONTEMPT-LT 28 computer Closed (SSER 2) codes (12) Reactor vessel cooldown rate Closed (SSER 2)
(13) SRV discharge testing Closed (SSER 3) 6.2.1.8.3 (14) Mark III-related issues Closed (SSER 2);
see Lic. Cond. 9 (15) Containment repressurization Closed (SSER 2)
(16) Inleakage limit Closed (SSER 1)
(17) ECCS test return line design Closed (SSER 1)
(18) Containment purge valves-Closed (SSER 2)
(19) Hyd'rogen control Closed for initial license (SSER 2)**
(20) PVLCS leakage Closed (SSER 2)
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b See footnotes at end of table.
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River Bend SSER 3 1-B
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SSER 3 Issue Status
- Section(s)
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(21) Electrical and instrumentation and Closed (SSER 3) 7.1.6 L
control diagrams l
(22) Routing of circuits and sensors closed (SSER 2) l (23) Instrumentation setpoints Closed (SSER 3) 7.2.2.2 (24) RPS power supply protection Closed (SSER 3) 7.2.2.3 l
l (25) RPS and ESF channel separation Closed (SSER 3) 7.2.2.4 (26) Isolation devices Closed (SSER 3) 7.2.2.6 (27) Reactor mode switch Closed (SSER 2)
(28) ADS actuation Closed (SSER 2)
I (29) ESF reset controls Closed (SSER 3) 7.3.2.4 (30) Initiation of ESF support systems Closed (SSER 3) 7.3.2.7 1
- 31) Instrumentation and control power Closed (SSER 3) 7.4.2.1 bus loss (32) RCIC system Closed (SSER 3) 7.4.2.2 (33) Standby liquid control system Closed (SSER 2)
(SCLC)
(34) Postaccident monitoring Closed (SSER 3);
7.5.2.4 instrumentation see Lic. Cond. 17 (35) Temperature effects on level Closed (SSER 2) measurements (36) High/ low pressure interlocks Closed (SSER 3) 7.6.2.2 (37) End of cycle recirculation Closed (SSER 2) pump trip (38) NMS and RCIS isolation Closed (SSER 3) 7.6.2.5 (39) Red pattern control system Closed (SSER 3)
- 7. 6. 2. 6 microprocessors
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(40) DRMS Closed (SSER 3) 7.6.2.7 i
See footnotes at end of table.
River Bend SSER 3 1-9
Table 1.4 (Continued)
I SSER 3 Issue Status
- Section(s)
(41) High-energy line bredk control-Closed (SSER 3) 7.7.2.1 system failures (42) Multiple control system failures Closed (SSER 3) 7.7.2.2 (43) Emergency Response Information Closed (SSER 2)
System (ERIS)
(44) LPCS/RHRA pump procedures Closed (SSER 3) 8.3.1 I
(45) EPA /RPS motor generator set Closed (SSER 2) interconnection (46) Second level undervoltage pro-Closed (SSER 3) 8.4.1 tection relay setpoint (47) Verification of.. test results for Closedt station electric distribution system' voltage (48) Safety cable identification Closed (SSER 2)
I (49) Non-Class 1E loads powered
_ Closed (SSER 3) 8.4.6 from Class 1E power supplies (50)'Postaccident sampling system Closed (SSER 2)
(51) Diesel generators - mechanical Closed (SSER 2) issues (52) TMI Item II.F.1, Attachment 2 Closed (SSER 2)
(53) Spent fuel transfer canal Closed (SSER 1)
(54) TMI Item II.B.2 Closed (SSER 2)
(55) Backup RPM designate Closed (SSER 2)
(56) Personnel rdsumis
. Closed (SSER 2)
(57) Licensed operator review Closed (SSER 2)
(58) Offsite fire department training Closed (SSER 2)
(59) Emergency planning Closed (SSER 3) 13.3
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See footnotes at end of table.
River Bend SSER 3 1-10 i
Table 1.4 (Continued)
SSER 3 Status
- Section(s) assue (60) TMI Item I.C.1 Closed for initial 13.5.2.2, license (SSER 3) 13.5.2.3 (61) Initial test program revisions Closed (SSER 3) 14 (62) Proper ESF function (II.K.1.5)
Closed (SSER 2)
(63) Safety system operability status Closed (SSER 2)
(II.K.1.10)
(64) QA organization Closed ($5ER 1)
(65) Ultimate heat sink with delayed Closed (SSER 3);
9.2.5 see Lic. Cond. 20 fan start (66) Participation of human factors Closed (SSER 3);
18.1 specialists in detailed control see Lic. Cond. 17 room design review (67) Task analysis documentation Closed (SSER 3) 18.1 (68) Control room modifications Closed (SSER 3);
18.1 see Lic. Cond. 17 (69) Containment venting procedures Closed (SSER 3);
13.5.2.3 j
see Lic. Cond. 17 l
(70) Monitoring instruments for HPCS Closed (SSER 3) 8.3.2 125-V ac system (71) Protection for lighting Closed (SSER 3) 8.4.2 penetration circuits (72) Process Control Program Interim approval until first refueling outage (SSER 2)
(73) Subcompartment pressure analysis Closed (SSER 2)
Closed (SSER 2)
(74) Cable derating
- License condition references are as numbered in Table 1.5.
- Reclassified as Outstanding Issue 23 tAssigned to Region IV by the low power license.
(-
1-11 River Bend SSER 3
i Table 1.5 Listing of license conditions (revised from SER)
(
Status SER Section(s)
, sue (1) Oil and gas exploration Resolved (SSER 2) 2.2.2 (2) Turbine system mainte' nance program Unchanged from SER 3.5.1.3.3 (3)
Fuel rod internal pressure Removed (SSER 1) 4.2.1.1 (4)
Inadequate core cooling Removed (SSER 3) 4.4.7 (TMI Item II.F.2)
(5)
ESF reset control Included in Confirm-atory Item 29 (SSER 1)
(6) Postaccident capability Removed (SSER 2) 10.4.6 (TMI Item II.B.3)
(7) Solid waste process control program Removed (SSER 2) 11.4.2 (8) Partial feedwa.ter heating Unchanged from SER 15.1 (9) Mark 5II-related issues Unchanged from SER 6.2.1.9 4
j (10) Operating staff experience Unchanged from SER 13.1.2.1 requirements (11) Emergency preparedness 13.3 q
(12) Seismic and dynamic qualification 3.10 of seismic Category I mechanical and electrical equipment 1
3.11 (13) Equipment qualification (14) Inservice inspection program 5.2.4.3, 6.6.3 I
7.5.2.2 l
(15) Bypassed and inoperable status indication i
8.3.1 l
(16) TDI diesel engines i
(17) Emergency response capabilities 18.1. 18.1.2.8, 7.5.2.4 7.2.2.5 (18) Salem ATWS - Generic Letter 83-28 requirements 9.5.1 (19) Fire protection
(
9.2.5 l
(20) Ultimate heat sink 13 (21) Operating staff experience requirements 1
River Bend SSER 3 1-12 g
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