ML20134E867
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From:
Linda J. Watson (LJW2),/
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OEMAIL Date:
Thursday, June 16, 1994 4:45 pm j-
Subject:
Vogtle EA 94-087 Here is a copy of the package that was signed by Mr. Ebneter today for Vogtle enforcement action 94-Od7. This is being sent overnight mail to OE, NRR, and OGC.today.
Linda
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CC:
JRG1, LAR1, BXU, JRG, BTS, MAS Files:
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Docket No. 50-424 U. S. Nuclear Regulatory Commission Oi ATTN: Document Control Desk Washington, D. C. 20555 "i
Ladies and Gentlemen:
VOGTLE ELECTRIC GENERATING PLANT REVISION TO LICENSEE EVENT REPORT E
CLOSED DAMPERS RENDER TWO TRAINS OF HVAC IN
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Georgia Power Company submits the enclosed report as a revision to Report dated May 26,1994, related to an event which was initially repo per 10 CFR 50.72 (b)(2)(iii) on April 26,1994, and discussed with the NRC at a Enforcement Conference on June 2,1994.
Sincerel,
C. K. McCoy CKM/AFS
Enclosure:
LER 1-94-003-1 xc:
Georeia Power Comnany Mr. J. B. Beasley, Jr.
Mr. M. Sheibani l
NORMS
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- al U. S. Nuclear Regulatory CommissioD Mr. S. D. Ebneter, Regional Administrator
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Mr. D. S. Hood, Licensing Project Manager f
Mr. B. R. Bonser, Senior Resident Inspector, Vogtle
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A. REQUIREMENT FOR REPORT i
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This report is required per 10 CFR 50.73 (a)(2)(v) because a condition existed that alone could have i
prevented the fulfillment of a safety function of a system needed to control the release of radioacuve -
material. It is also required per 10 CFR 50.73 (a)(2)(i) because the unit operated in a condition l
prohfoited by the Technical Specification (TS) when a system was inoperable for a period of time j
longer than that allowed by the action statement.
l j'
B. UNIT STATUS AT TIME OF EVENT i
i At the time of this event, Unit I was operating in Mode 1 (power operations) at 100 percent of rated thermal power. Other than that described herein, there was no inoperable equipment that contributed j
to the occurrence of this event.
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l C. DESCRIPTION OF EVENT The Unit 2 electrical penetration filtration system had never been installed and as part of a design change to abandon the Unit I system, on February 28,1994, and March 1,1994, personnel installed j
clearances by opening the applicab'e circuit breakers. These clearances removed power to several j
dampers in this filtration system. However, power was also unknowingly removed to piping penetration area filtration and exhaust system (PPAFES) train A and B exhaust dampers, IPV-l 2550B and IPV-2551B, because they share circuit breakers with the system being abandoned. This left the PPAFES exhaust dampers in their closed positions and inoperable. These exhaust dampers j
open to preset positions to maintain negative pressure during PPAFES operation. Thus, the PPAFES was limited in its ability to control the release of radioactive materials from the piping i
penetration rooms, had it become n cessary to do so in a post-LOCA scenario.
I j
TS surveillances were performed for the Train A PPAFES on March 15,1994, and April 11,1994, j
and for the Train B PPAFES on March 28,1994. Personnel noted that the position indication lights, i
used for verifying modulation of dampers IPV-2550B and IPV-2551B, were not illuminated during i
these surveillances. During the March 28,1994, surveillance, an investigation of the apparent l
j position indication problem was initiated, but was not pursued due to shift tumover. Since the l
acceptance criteria for the surveillance was met, the surveillance was signed off as satisfactory. A i
more thorough and complete investigation was conducted during the April 11,1994, surveillance.
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Visual indication of IPV-2550B valve linkage led the personnel involved to believe that the valve 1
i had actually moved to its preset demanded position, and a work order was initiated to effect repairs of the position indication. On April 20,1994, an investigation by an electrician, per the work order, revealed that both the indicator lights and the dampers were removed from service because the I
power had been removed. The unit shift supervisor (USS) was notified that the position indication was lost due to the breakers being open. However, he did not realize that opening the breakers had also removed power to the dampers. On April 24,1994, during work order closcout, another USS i
recognized the impact on the PPAFES. While reviewing the clearance for modification to reenergize i
the exhaust dampers, PPAFES testing was performed to determine operability. System flows, differential pressures, and alarm indications all indicated normal, with the only abnormality being the j
indication for the exhaust dampers. After discussion of the test results with the system engineenng j
supervisor and plant management, an initial determination was made that this condition had not i
rendered the system inoperable. However, plant management requested a design review of this '
I condition to determine the complete impact to the PPAFES. Power was restored and the system i
returned to service.
1 On April 25,1994, the design engineering staff began to evaluate the effect of the deenergized l
dampers on the operability of the system and on April 26,1994, it was determined that PPAFES had been rendered inoperable and that the safety function of the system had been degraded by the dampers being deenergized while in their closed positions. A four-hour non-emergency notification was made to the NRC Operations Center per 10 CFR 50.72 (b)(2)(iii) because a condition existed that alone could have prevented the fulfillment of a safety function of a system needed to control the release of radioactive material.
A broadness review initially found that similar events had occurred when damper circuit breakers were deenergized for one train of PPAFES on three other occasions. Further review of clearances has shown only one occasion when one train of PPAFES had been rendered inoperable for a period of time longer than that aliowed by the TS. The Unit I train A breaker was deenergized from October 28,1988, to November 9,1988.
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D. CAUSE OF EVENT The causes of this event were:
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- 1) Drawing discrepancies
- 2) Inadequate review of circuit breaker clearances
- 3) Surveillance guidance for dampers was unclear
- 4) Failure to discover event earlier i
j These causes are detailed as follows:
- 1) A single line diagram and electricalload list failed to specifically identify by equipment number.
1 that the train A exhaust damper was a device being powered from the affected circuit breaker. The i
single line diagram and electrical load list identified other dampers and an HVAC panel as devices being fed from the circuit breaker which was deenergized on February 28,1994. However, the train i
A exhaust damper was also being fed from this circuit breaker via the HVAC panel.
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- 2) Cognitive personnel error and lack of attention to detail by the operations work planner and the support shift supervisor (SSS) resulted in an inadequate review of the circuit breaker clearance associated with the design change on the train B components. The operations work plannefs and i
SSS's reviews did not find the PPAFES train A exhaust damper on the appropriate breaker drawing I
I or its respective load list because it was not listed on these documents. The PPAFES train B exhaust I
damper was shown on its respective drawing and load list, but these were not adequately reviewed since the train A and train B clearances were being developed at the same time.
i 1
- 3) The purpose of the monthly surveillance is to operate the system to prevent moisture buildup on the filter. This monthly surveillance contains no acceptance criteria related to proper exhaust damper i
operation, and procedural guidance for checking status of the exhaust damper was unclear.
However, the monthly surveillance did provide opportunities to identify the clearance error.
- 4) Subsequent personnel errors committed during performance of surveillance testing and.
j investigation of the damper position indication discrepancy prevented the early detection and correction of the clearance error.
The occurrence of these cognitive personnel errors by the Georgia Power Company personnel i
involved was not the result of any unusual characteristics of the work locanon.
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The functions of the PPAFES are to mamtam a negative pressure boundary on the piping penetration area rooms and to filter the exhaust from those areas. Safety Evaluation Report dated July 9,1992, -
assumes iodine leakage from the piping penetration rooms and emergency core cooling system I
(ECCS) equipment to both offsite and control room locations during post-LOCA conditions.
l Therefore, the control room and offsite dose analyses are potentially affected by the degradation of this system caused by the inoperable exhaust dampers.
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l Based upon the latest dose analysis, had the ECCS leakage risen to the design basis analyzed value of
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2 gpm with the PPAFES exhaust dampers closed, the offsite dose would have remained within the 10 1
CFR 100 limits, and the control room dose would also have remained within the General Design Criteria 19 acceptance criteria.
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l Several other factors also existed that would have mitigated the consequences of this scenario:
l l
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The latest surveillance value for ECCS leakage, based on the requirements of TS 6.7.4 and taken during the last Unit I refueling outage, indicated the leakage was less than 0.1 gpm.
l This would result in the expected source term being significantly less than the 2 gpm assumed in the design basis dose analysis.
i Although the PPAFES exhaust dampers were inoperable and would have resulted in an increase of radioactivity release, the filter and recirculation function of the PPAFES was operable and would have filtered out a majority of the airborne radiation resulting from ECCS leakage.
Combining these two conditions of a low ECCS leakage value and the operability of the recirculation / filtration function of PPAFES being unaffected by the inoperability of the exhaust dampers, results in maintaining the expected source term within the d: sign basis dose analysis value.
2)
ECCS leakage which occurred would enter the auxiliary building in interior rooms below grade, and have to diffuse through several rooms or be transported via the filter system to rooms bordering on the exterior of the building prior to release. After filtration, the expected discharge flow of 2700 cfm would have been returned with the recirculation flow of 11760 cfm to the various ECCS rooms. These rooms are typically provided with sealed
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, % =4m penetrations and solid doors (not wire mesh) maintained closed for flood protection, radiation protection, fire protection, etc., and would provide a substantial barrier to radioactivity release. Therefore, the majority of the leakage would be processed through the PPAFES j
filters, perhaps being recirculated several times, prior to release. The leakage which bypasses -
the filters would have a long winding pathway to follow prior to exiting the auxiliary building and would be subject to natural removal processes along the way, such as settling and j
plateout.
3)
The PPAFES charcoal filter iodine removal efficiency is supplemented by heaters that aid j
in decreasing humidity. Since the expected relative humidity at the charcoal filter inlet (following the guidance of Regulatory Guide 1.52) is much closer to the controlled environment value of 70 percent than to the uncontrolled environment value of 95 percent, the PPAFES efficiency ofiodine removal would be greater than that taken credit for in the
- j design basis dose analysis. In addition, the filter actually has a bed depth of four inches as opposed to the two inches taken credit for in the accident analysis. Therefore, the recirculation / filtration which would occur would be more effective than discussed above.
Finally, there was no leakage event during the period of time involved. Based on these considerations, there was no adverse effect on plant safety or on the health and safety of the public as a result of this event.
F. CORRECTIVE ACTIONS i
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- 1) Power was immediately restored to the exhaust dampers on April 24,1994, following discovery of the clearance error impact on the exhaust dampers.
- 2) The appropriate Unit I and Unit 2 single line diagrams and electrical load lists, which failed to identify by equipment number that the Train A PPAFES exhaust damper was being powered from the circuit breaker, have been corrected.
- 3) The individuals involved have been counseled on the significance of configuration control when preparing, reviewing, and approving clearances, and timely identification of abnormal equipment status indications.
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- 4) The PPAFES monthly surveillance and system operating procedures have been revised to provide clearer guidance on verifying exhaust damper operation. Operations surveillance procedures will be reviewed to ensure guidance that determines equipment status is clear and consistent. This review will be completed by July 15,1994.
- 5) An initial sample review of other breakers that power similar loads revealed no further drawing problems. An additional review will be completed by September 1,1994.
- 6) The operations work planners and system engineers have been provided training regardmg this event, with emphasis on configuration control. Licensed operators will review this event in continuing training by July 15,1994, with particular instruction on configuration control. Emphasis j
will also be given to utilizing a questioning attitude when test indications are not clearly understood.
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- 7) An evaluation of the exhaust damper portion of the system for possible improvements is in progress and recommendations for system and procedure improvements will be made by July 1,1994.
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G. ADDITIONALINFORMATION 1)
Failed Components:
None 2)
Previous Similar Events:
None 3)
Energy Industry Identification System Code:
Emergency Core Cooling System - BJ, BP Piping Penetration Air Filtration and Exhaust System - VA
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UNITED STATES NUCLEAR REGULATORY COMMISSION j
OFFICE OF PUBLIC AFFAIRS, REGION II 101 Marietta St.,, Suite 2900, Atlanta, GA 30323
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Tel. 404-331-5503 No.:
11-94-57 FOR IMMEDIATE RELEASE
Contact:
Ken Clark (Friday, July 1, 1994)
Telephone:
404-331-5503 NRC STAFF PROPOSES $25,000 CIVIL PENALTY AGAINST GEORGIA POWER FOR ALLEGED VIOLATION OF NRC REQUIREMENTS AT V0GTLE NUCLEAR PLA The Nuclear Regulatory Commission staff has proposed a $25,000 civil penalty against Georgia Power Company for alleged violation of NRC requirements at the Vogtle nuclear power plant, operated by the company near Waynesboro, Georgia.
In a Notice of Violation dated June 30, 1994, NRC officials told the company that the fine was being proposed because of a problem identified by the company at the plant on April 24, 1994, and reported to the NRC.
The NRC said the power supply for exhaust dampers on both trains of the Unit 1 piping penetration area filter and exhaust system were deenergized from March 1, 1994 until identified by the plant staff.
The NRC said plant operators had numerous opportunities to identify and correct the problem.
The NRC said one safety function of this system is to maintain a negative pressure in the piping penetration rooms so that air would flow inward in the event of a leak.
When the electric power rupply to the dampers was cut off in error, they failed closed and caused the system to lose its ability to maintain negative pressure in some of the rooms served by this system.
The base civil penalty for this violation is $50,000, but NRC officials said it was reduced in this case to $25,000 because of the company's immediate corrective actions when the problem was identified.
The dampers were promptly reenergized, appropriate drawings were corrected, surveillance procedures were clarified, involved individuals were counseled, and a case study was initiated to review and correct the causes of the problem.
The company has 30 days from the date of the Notice of Violation to either pay the civil penalty or to protest it.
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EA 94-oe7
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CHECKLIST ROI 0917 EVALUATION OF LICENSEE CORRECTIVE ACTIONS FOR VIOLATIONS Inspection Rpt No. 94-15 Violation No.50-425/94-15-02 Plant Name_ Voatle Units 1 and 2 Response Received 07/25/94 ASSESSNENT BY RII NANAGERS OF LICENSEE'S CORRECTIVE ACTION:
Was the Root Cause for the Violation Addressed? If no, explain.
yes Were the Steps Taken Adequate to Correct the Problem and Prevent Future Violation?
ves Results Achieved: Power was restorert to the dampers: the line diaarams and electrical load lists were corrected: involved Dersonnel Were counseled: surveillance and system operatina procedures were revised:
trainina was provided to operations work planners and system enaineers:
the exhaust daBDer Dortion of the system was evaluated foe imDrovement:
licensed oDerators received trainina on configuratiQn control: and a sample review of drawines for other breakers that p e ar similar loads was Derformed.
Additional Corrective Steps That Nill Be Taken:
An additional review of drawines for other breakers that Dower similar loads Will be completed by September 1.1994.
Date of Full Compliance Indicated: April 24. 1994 tL% lf 7p61W' Section Chief '
Date Recommended Actions:
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Response tetter Telephone Call To Licensee O
tetter Requesting Suppiementai Information Approved By:
D 7 l(>/ 9r'
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Brknch Chief Date cc:
Division Director
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t Original to Docket File
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A' 40 inverness Center Pgrzwsv Post O&c3 Box 1295 B'rmmgn:m Anoama 35201 1
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j LCV-0370-D Docket Nos. 50-424 50-425 Director, OfEce ofEnforcement U. S. Nuclear Regulatory Comnussion ATTN: Document Control Desk Washington, D. C. 20555 Ladies and Gentlemen:
VOGTLE ELECTRIC GENERATING PLANT i
REPLY TO A NOTICE OF VIOLATION AND PAYMENT OF l
PROPOSED IMPOSITION OF CIVIL PENALTY I
Pursuant to 10 CFR 2.201, Vogtle Electric Generating Plant (VEGP) submits the enclosed information and check in the amount of $25,000 in response to a notice ofviolation and proposed imposition of civil penalty. The violation was identi6ed during an inspection conducted from April 24 - May 12,1994, described in Inspection Reports 50-424,425/94-15, and dir=M with NRC Region II at an Enforcement Conference on June 2,1994, i
Should you have any questions, please contact this of5ce.
Sincerely, N
C. K. McCoy CKM/AFS/WCG
Enclosures:
Reply to NOV 50-424,425/94-15 and $25,000 check.
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u o o n evs oe t,
2 Nac Poam see U.S. RUCLEAR CE!ULATORY COh.lSSION "vo'C NUMeeR I
(96 INVOICE
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o Maan CHECES PAYAeLE TO THE U.S. NUCLAAR AGOULATORY COMMISSION. REFERENCE THE INv0 C4 NUMe&R ON REMITTANCE, AND wVOICI DATE u.S. NUCLEAR REGULATORY COMMISSION DIVISION OF ACCOUNTING AND FINANCE OFFICE OF THE CONTROLLER July 26, 1994 WASHINGTON, DC m uCsNsa NUMesR rn aMaesmer 73 REFERENCE NUMeER r# em CONTACT Georgia Power Coupany NAMs Post Office Box 4545 Atlants, GA 30302 m iP oNi l NuMe R ARtA CODE aos
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DESCRPTION AMOUNT Recsived full payment for EA 94-087, dated June 30, 1994,
$25,000 Docket Nos. 50-424 and 50-425
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AMOUNT DUE rs T->
S25,000 TERMS.' interest wHi accrue frorn the irwcace dote et the annual rete of
%. Payment is due 'T.T - n._.. However, interest will be werved if payment is recorved wrthin 30 deve from the invoice date. Peneity and admnustrotrve charges will be acesomed on a delinguent invoice. Addatened terms and con.
detene are attached, if applicable NOTE.
If there are any guestens about the emetence or amount of the debt, contact the indmdual named above. For NRC debt collection procedures, ir caudme imerest and penelty provemens, see 31 U.S.C. 3717,4 CFR 101-106, and 10 CFR 15.
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- TWENTY-FIVE THOUSAND ****
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$25,000.00 i
To ts e ordee of TREASURER OF THE UNITED STATES U. S. NUCLEAR REGULATORY C0lWISSION WAS:lINGTON DC 20555 c - '- i.== = re.e '- s'o.ooo -
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First Urwon Netronal Bar*, Chapel Hill. MC.
Aumentree sa, net-e Assistent Treasurer BN 50020 e5580&3e e:0 5 310 L SE Es: 20 7998 5 28E SE ?e 1
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July 21, 1994 LCV-0370-D Docket Nos. 50-424 50-425 Director, OfBee of Enforcement U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555 Ladies and Gentlemen-VOGTLE ELECTRIC GENERATING PLANT REPLY TO A NOTICE OF VIOLATION AND PAYMENT OF PROPOSED IMPOSITION OF CIVIL PENALTY Pursuant to 10 CFR 2.201, Vogtle Electric Generating Plant (VEGP) submits the enclosed information and check in the amount of $25,000 in response to a notice of violation and proposed imposition of civil penalty. The violation was identified during an inspection conducted from April 24 - May 12,1994, described in Inspection Reports 50-424,425/94-15, and discussed with NRC Region II at an Enforcement Conference on June 2,1994.
l Should you have any questions, please contact this office.
i Sincerely, N
C. K. McCoy CKM/AFS/WCG
Enclosures:
Reply to NOV 50-424,425/94-15 and $25,000 check.
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,,_TEL 301-504-2102 Aug i7'94 16: 42 No.014 P.02 sf
()t e,eenor, aos arr.ma Vse P6 Nucear i
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Augut 17,1994-LCV.4374 F Dochut No. 50 424 Mr.Jamm1Jeberusa -
Diressor;05os ofEntroement U. S.NudsarEsguistory P%
Washlageon,D. C. 20555 VOOTLEELECTIUC GENERATINGPLANT REPLY TONOTICE OF VIOLATION AND PROPOSED IMPO5rIION OF'CIVE,-
PENALTHIS FJL91404 1
Dear Mr. T.ishannan-1
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The purpoes of thle letteris to amend a semannes on page 6, paragraph 5 in Georgip Power i
Company's cover letter so Mr. James IJabarama dated July 31,1994, which describes the counseling of the Unit Superintendent by the Senior Vice Presidses <leorgia Power raay==y (GPC). This======i====e is insemind to asshe cieer that pdor to July 31,1994, ths Senior Vice President - GPC had s de ith the Unit U_
M but that w
counnsbag pursuant to haharn Nuclear Opersang Company's Posidvs Discipline System did not ooouruntil August 16,1994. The sentanos shouldseedu Aillows-i 4
'Ihs Senior Vlas President - Georgia Power Compsey (GPC), in =Maiaa to -
i counselhas with the Vogde Blaside GemmesissPlans(VEGP) GememLManager, as disomeed in the Response to the Demand ihr Intrmation regenling the VEGP osneral Manseer, has abo ' et wkh the Unit Supedmodest and discussed abs-m needtoassureunetinconn eianisnotaw aar-t In l
% on August.16,1994, antiraissanindstras comemaplated.by Southenr i
Nuclear Operusing Company's Peakive Diamplies Symans was hakiwith alwUnit j
u astan==daarbyhis ;1/_ andtheSedarViarrPtosident-GPC. 'Ihey v
i dissueuesthe Unit:8uperistemdess'Webum====voisteibto theNOV8'.imir j
fbaused upon ways in wbl4 he coul imptove his manswian to detail to ename that j
his wade is thesougitand promism and that ha M.withothern 4
l Also endosed is an errats sheet fiar Georgia Power Company's rapiy.to the Notics of l
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NRC LRPE TEL 701-504-2102 Aug 17'94 16: 42 No.014 P.03 Georg!aRmerA Mr.Jannes Usbonnea Pass 2 We regret any inconvenimace tids===admaar may cuaes you.
sincerity, h h.
C. K. MsCoy CKM/ JAB /sub Endoeure oc-GuarmiaPawar commmer Mr. J. a. asemier, Jr.
Mr.u. shebani NGEME U. S. Nualamr RapistoryCanuminden Mr. s.n. numer,nasionsudadmisamor Mr. o. s. sood. uosadag Prq)ea Manger, NRK Mr. B. R. Bonner, senior Ranid== Inspector, Vogde h==* Contml Desk 1
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usNRC DRPE TEL 301-504-2102..
.9ug 17'94. 16: 43 30.0g j.04 l
wn= rrA Lremer *mGnarmW 4 LOCATION REFERENCE CORRECfED REFERI2KZ 1
Page 3,ibotness 5 "GPC Transmipt*
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o ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE e
INFORMATION RE0VIRED TO BE AVAILABLE PRIOR TO ENFORCEMENT PANEL PREPARED BY:Bonser DATE PREPARED:11/07/94 NOTE:
The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel.
(This information will be used by EICS to prepare the enforcement letter and Notice, 1
as well as the transmittal memo to the Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
1.
Facility: Voatie Unit (s): One Docket Nos:
50-424 License Nos: NPF-68. NPF-81 Report Nos:
424.425/94-26 Inspection Dates:
10/16/94 - 11/19/94 Lead Inspector:
Bonser 2.
Notes:
A.
A draft Notice of Violation, including the recommended severity level for each violation, should be enclosed. The violation (s) in the Notice should be carefully considered by both'the inspector and Section Chief, and should be comolete regarding the specific j
requirement to be cited and the appropriate level of specificity as
)
to how and when the requirement was violated.
B.
Copies of applicable Technical Suecificatioas or license conditions cited in the Notice should be enclosed.
3.
Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) e.g., Supplement I.C.2) i I.C.2.(a)
..THIS DOCUMENTgCONTAINS PREpEfCIs AL INFORMATION-f IT CAN Npt BE mSCLOSED TSIDE NRC HOUT THE
[.$
AP OVAL OFTHE lONAL ADMINISTR i
j i
ESCALATED ENFORCEMENT PRE-PANEL OVESTIONNAIRE 2
4.
What is the apparent root cause of the violation or problem?
Several causes of this event which resulted in an inadeauate review of the desian chanae:
- An inadeauate colicy for maintenance of drawinas (Interconnectina Wirina Diaarams) and manuals.
- The Minor Desian Chanae (MDC) crocess oermits too much leeway for interpretation of what is an MDC and allows too much flexibility for what can be included in the MDC Dackaae.
- Corrective action for a previous similar event was not completed in a timely manner (see NRC IR 424.425/93-04 & 93-07).
This involved uodate of the card load list.
-< LeksonsMbarned/ rom everit crittaues were not forwarded to Sbuthetry NuclW in EhrMnahhm/
W/ V
- Policy on eauipment abandonment did not exist at time of desian develooment.
i 5.
State the message that should be given to the licensee (and industry) through this enforcement action.
The initial scope of desian chances should be accurately developed j
for interdisciplinary review if necessary.
Desian chanaes must be adeauately reviewed with accurate desian documents orior to imolementation in the field.
The licensee should have a aood feedback mechanism to ensure corrective actions are completed.
6.
Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2):
a.
IDENTIFICATION:
(Who identified the violation? What were the facts and circumstances related to the discovery of the violation?
Was it self-disclosing? Was it identified as a result of a generic notification?)
Self identifyina durina the performance of Operations surveillance orocedure 14515-1. Pioina Penetration Area Filtrati6n and Exhaust System Operability Test on October 27. 1994.
Operators observed that the oicina cen. system flow controller did not shift to AUTO when the system was started.
--THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE-fac wiTHOQ ROIAL OF THE'REOtOffAL ADMINISTRATOR
ESCALATED ENFORCEMENT PRE-PANEL OVESTIONNAIRE 3
b.
CORRECTIVE ACTION:
Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
Immediately reolaced circuit (NDI) cards.
All work on MDCs was stocoed until they are all re-reviewed.
Other corrective action on this event has not been finalized by licensee.
The licensee indicates they will fix errors in Interconnectina Wirina Diaarams (IWD). correct the Card Load List and correct the adeauacy of administrative controls of drawinas and documents. Other areas include the desian chance Droarnm and the corrective action orocram.
What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions?
Train "A" Ploina Penetration ND! card reolaced.
Proper damner oDeration and flow throuah verified 10-28-94.
Train 8 oicina Den NDI card replaced and orocer damoer coeration and flow throuah verified.
What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis?
Licensee took immediate action in restorina system to service by NDI card replacement. and immediately started conductina an i
investiaation to identify cause.
Investiaation is near completion at the time of this writina, c.
LICENSEE PERFORMANCE: This factor taken into account the last two years or the period within the last two inspections, whichever is longer.
f List past violations that may be related to the current violation I
(include specific requirement cited and the date issued):
Reports: 50-424.425/93-07 dated May. 1993 violation for failure to take adeouate corrective action results in loss of decay heat removal and 50-424.425/94-15. April 1994 oroblems in Pioina Penetration system not oromotiv identified and corrected.
-THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION-T-CAftNO(BE DISCLOSEDESIDE NRC WITHOjUT T E._.
j APPROV At-OF -THETEGION AL 3DM4MSTRATO R 1
4 ESCALATED ENFORCEMENT PRE-PANEL OVESTIONNAIRE 4
Identify the applicable SALP category, the rating for this category and the overall rating for the last two SALP periods, as well as any trend indicated:
Ooerations SALP - 2 last two oeriods. Enaineerina SALP - 1 last two Deriods d.
PRIOR OPPORTUNITY TO IDENTIFY:
Were there opportunities for the licensee to discover the violation sooner such as through normal surveillances, audits, QA activities, specific NRC or industry notification, or reports by employees?
Only durina desian chanae modification review of 93-VIM 138-0001 (Elimination of Electrical Penetration HVAC system) would thgig circuit cards have been identified as sharina locos with the oioina oenetration system.
e.
MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this inspection?
If there were, identify the number of examples and briefly describe each one.
No.
f.
DURATION: How long did the violation exist?
Aoorox 9 days (THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION-MANWOT~BE~DISQLOSED OUTSIDE NRC WITHOUT THE s
APPROVAL OF THE REGIONAL ADMIN e
O ESCALATED ENFORCEMENT PRE-PANEL OVESTIONNAIRE 5
ADDITIONAL COMMENTS / NOTES: At aooroximately 1007 am on October 28. 1994. with Units 1 and 2 at 100% oower. followina an investiaation into the cause of a Unit 1 A train Pioina Penetration Filtration System exhaust damper that malfunctioned while cerformino a surveillance. it was determined that bettrm trainmand B. train of"the Pioina Penetration Filtration Systems were inosm L3e:
e This could have orevented the fulfillment of the Pioina Penetration HVAC System function needed to control the release of radioactive material.
Althouah the Pioina Penetration Filtration System filtration functions would still occur.
the malfunction of the exhaust damper could have affected the ability to maintain a neaative cressure in Auxiliary Buildina rcoms served by the system.
i Technical SDecification 3.0.3 was entered at 1007 am on October 28. 1994. and exited at 1030 am followina restoration of the A train Pioina Penetration Filtration System.
The B train Pioina Penetration System was restored at 1140 am on October 28. 1994.
On 0ctober-19r.1994, while imolementina a desian chanae to abandon an i
electrical oenetrat1on HVAC system. the-associated A and B train electrical Denetration system NDI cards were removed.
At 1032 om on October-273 1994.
While performino a surveillance on the Unit 1 Pioina Penetration Filtration System. the exhaust damper was observed not to automatically coen as exoected.
and the system LCO was entered.
Subseauently. followina the review into the A J
train surveillance failure. it was determined that unknown common elements of the Electrical Penetration system NDI cards disabled the Pioina Penetration Filtration System damper oermissive and control function.
The Licensee immediately initiated an investiaation into the event to determine the root cause.
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ENCLOSURE 1 NOTICE OF VIOLATION Georgia Power Company Docket No.
50-424 Vogtle Electric Generating Plant License No. NPF-68 Unit 1 4
'During the NRC inspection conducted on October 16 - November 19, 1994, violation (s) of NRC requirements was identified.
In accordance with the
" General Statement of Policy and Procedures for NRC Enforcement Actions," 10 CFR Part 2, Appendix C, the violation is listed below:
10 CFR Part 50, Appendix B, Criterion III, " Design Control" requires, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews.
Contrary to the above, the licensee failed to ensure that design control measures provided for verifying the adequacy of a design change to abandon the i
Unit 1 electrical penetration area filtration and exhaust system.
This j
resulted in disabling the automatic function of the Piping Penetration Area 1
Filtration and Exhaust System (PPAFES) train "A" and "B" exhaust dampers, and the exhaust function of the PPAFES remaining in a disabled condition for approximately nine days.
This failure to ensure that design control measures provided for verifying the adequacy of the design change is evidenced by the following examples:
THESE CAN BE ADDED IF NECESSARY OR WILL BE IN BODY OF INSPECTION REPORT.
This is a Severity Level III violation (supplement I).
4 Pursuant to the provisions of 10 CFR 2.201, Duke Power Company is hereby required to submit a written statement of explanation to the U. S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, D.C. 20555, l
with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident Inspector Vogtle Nuclear Plant, within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should be 4
clearly marked as a " Reply to a Notice of Violation" and should include for i
each violation:
(1) the reason for the violation, or if contested, the basis
~
for disputing the violation, (2) the corrective steps that have been taken and the results achieved, (3) the corrective steps that wili be taken to avoid further violations, and (4) the date when full compliance will be achieved.
If an adequate reply is not received within the time specified in this Notice, an order or demand for information may be issued as to why the licensee should not be modified, suspended, or revoked, or why such other action as,may be proper l
should not be taken.
Where good cause is shown.
consideration will be given to extending the response time.
Dated at this day of
, 19 kHIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION-ITEANYdTBIEDISCLOSio vuiwullplRC APPROVAL OF THE REGIONAL A '
STRATOR
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e 11/9/94 ANALYSIS OF WATER HEIGHTIN STEAM GENERATOR TUBES This analysis adresses the condition of an RCS vented to atmosphere with the level of the water at elevation 192 feet and a temperature range of the water between 70F and 212F.
The model used considers that the SG U-tubes act as siphons, whether or not there is flow in the tubes.
The elevation of the top of the tube bundles is 224 feet. The analysis considers this elevation to be the worst case scenario of interest.
The Steam Tables used are the 1969 edition of Keenan, Keyes, Hill, and Moore.
The model used was extracted from the 1972 edition of Hicks " Standard Handbook of Engineering Calculations" page 3-382," Maximum Allowable Height for a Liquid Siphon".
The friction loss for a nominal flow of 1 gpm through a 0.688 nominal l
diameter tube was taken from Hicks page 3-376 Fig. 6 " Friction loss in water piping.
Calculation of Heiaht for 70F water i 70 degrees fahrenheit (F) i d 0 688 inches (in.), tube diameter 2
a=d square inches (sq in.), tube cross-sectional flow area 4
i = 34 feet (ft) of tube length from elev.192 to elev. 224, estimating curved part as 2 feet gpm = 1 gallons per minute (gpm), an assumed value EP" flow velocity in feet per sec (fps) v = 0.863 fps v-2 2.448 d p,
- 4.7 standard atmospheric pressure, Value used in Hicks pounds per square inch absolute (psia) y
= 61.69 lb/cu ft
.01621 P, :p,144 standard atmospheric pressure, pounds per square foot absolute (psfa) 11/W94 f
- s
t 11/9/94 p2 := 0.3632 vapor pressure of water at 70F,(psia)
- I'
- P P 144 vapor pressure of water at 70F,(psfa) 2 2
I f.= 0.016051 specific volume of water at 70F,
=62.301 lb/cu ft 2
cubic feet per pound (cu ft/lb)
.016051 p,, = I density of water at 70F, p,, = 62.301 lb/cu ft 2
pounds per cubic foot (lb/cu ft)
P IILP :=
head loss due to vapor pressure, feet of water (ft H2O) 2 9,
7 llLP, = 0.839 feet (ft)
IILV := 1.5 v head loss due to flow of water througli tube, feet of water (ft H2O) 2 IILV = 1.295 feet (ft) 2 IILF, = 0.314 head loss due to friction in the pipe, feet of water (ft H2O)
P h, =l- (IILP + IILY + IILF ) maximum height at 100F, feet of water (ft H2O) 7 2
2 2
Po i
h,, = 31.529 feet of water (ft H2O)et j
l I
j 11/9/94 l
.o 11/9/94 Calculation of Heiaht for 100F water feet of water (ft H2O) maximum height at 70F, feet of water (ft H2O) degrees F 1 - 100 d :0 688 inches (in.), tube diameter j
l 2
,ad square inches (sq in.), tube cross-sectional flow area 4
1': 34 feet of tube length from elev.192 to elev. 224, estimating curved part as 2 feet gpm.: I gallons per minute (gpm), an assumed value EP*
flow velocity in feet per sec (fps) y = 0.863 fps v-2 2 448 d p,
14.7 standard atmospheric pressure,(psia)
P, p,144 standard atmospheric pressure,(psfa) p, : 0 9503 vapor pressure of water at 100F,(psia)
P "P 144 V8Por pressure of water at 100F,(psfa) 2 2
q e
Value from Steam Tables f :0.016130 specific volume of water at 100F,(cu ft/lb)
I 2
= 61.996 lb/cu ft
.016130 p,:
density of water at 100F,(Ibicu ft) p,, = 61.996 3
2 lb/cu ft 11/9/94 t
--s t
w/
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i<
11/9/94 i
P head loss due to vapor pressure, feet of water (ft H2O) lil.P
=--
2 P oa i
4 IILP, = 2.207 feet (ft) liLV.= 1.5 v head loss due to flow of water through tube, feet of water (ft H2O) 2 ilLV = 1.295 feet (ft) 3 1115 :: 0 314 head loss due to friction in the pipe, feet of water (ft H2O) 2 p
h,.= 1 - (IILP + IILV + IILF )
maximum height at 100F, feet of water (ft H2O) 2 2
2 Po 7
4 i
j h, = 30.161 feet of water (ft H2O) l l
4 i
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i October 28.1994 RER 94-0317 RCS Configuration to Suppon Decay Heat Removal l
1 During the evolution of taking the reactor coolant syst 1
4 d
two trains of decay heat removal capability are required per Tech Spec 3.4.1.4 3.4.1.4.2. An allowable heat removal mechanism that can replace one trai l
steam generators with secondary side water level greater than 17% W.R.,
l coolant loops filled.
The requirement of reactor coolant loops filled require the RCS to be support decay heat removal. While RCS press i
pressure is reduced below 225 psi (RCP start criteria) natural circula process available to transfer heat to the steam generators.
l Voiding in the steam generator tubes can dismp h
top of the steam generator tubes. As the RCS j
as discussed in IN 94-36, NSAL 94 13 and RER 94 0182.
j What RCS condition, or pressurizer level is required to ensure decay he 1
capability through the steam generators is sufficient to require on j
operable while in Mode 5 (per Tech Spec 3.4.1.4.1).
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i E0*d BPS 6 PSS E 3115 31000 DM6n WdCE:10 5661-60-10
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i,,.,,,. l jlK.'h 7l, Request For Engineering Review
^ ' ^3 M RER NO.
Engineering Support Disposition f
5)'
Dispositiont 8:ckgroundt Tech Spec 3.4.1.4.1 requires 1 train of RHR operable AND either:
- 2. Two Steam Generators with secondary water Icvel above 17%.
when the plant is in mode 5 with the loops tilled.
l The heat removal mechanism with RHR is through l
Circulation which does not use forced or pumped tiuid movement. N RHR Heat Exchanger.
dh l
occurs due to differential pressure (DP) created between the heated wat i
t water in the steam generator tubes. This DP is c l
bility.
the water solid condition can result in flow blockage and loss of heat removal capa j
Doiling in the reactor core in shutdown condition i
i l
ii l
. Our. current Technical Specifications and proceduralized m t gatory prevention of core boiling for shutdown conditions.
i 16.1994. ISEG perfonned a Shutdown Risk Assessment of Unitl in cecordance with SNC procedure VSAER-WP 24. The results c On September f
F ti n of high risk due to the status of systems / components atiecting the i
The plant was in Mode 5 with the RCS being l'
d in operation.
atmosphere (via. removal of the primary code saf
(
l operator for valve IHV 8701 A (RCS loop 1-to-RIIR suction). Valve l
d in the under LCO l 44 2721.
li for open position to support operation of the RHR train for cooling. Tech Mode 5 "1. oops Filled" (3.4.1.4.1) was being met by maintaining level i i dh l t (SG's) greater than 17% WR, A clarification of Technical Specification l
i l
- peondition of RCS level greater than 192 ft. elevation as " oops SG maintaining SG's instead of the second RHR t f
i ii
' open to support reactor coolam pump motor maimenance and othe l
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Operations Policy 94/08/04 04. " Control of Outage Activities." provide f
activities on system operability. It states that "...as long as automatic operation of a its eperability requirements, performance of an MOV PM or test on a syst operability of that system so long as the valve could be placed in the required p rdaced in service in the necessary amount of time." In earlier di>cussions wit Planning supervision. the policy was further expanded to include instances wh h
were met if maintenance personnel could reposition valves as directed by the op function of the system.. This was the case with IHV 8701 A on September 16. A supervision. LCO l 94 2721 was originally generated due to the " exce be under the control of maintenance-making it too difficult to coordinate restor emergency. On the 16th. however, work was being performed only on 1H i
the that since the train was in operation and the valve could be positioned as required by i
train could be considered OPERABl.E. The decision to take credit for the SG This decision wus on the ficxibility afTorded by the existing Technical Specification clarification.
supported by Outage and Planning. and Operations management as opp Although. by appearance, all Technical Specification conditions were m of the SG's to perform their function as a heat sink in the event of a loss o h
explained in T.S. Bases 3/4.4.1) with the RCS level a fhh h
an OPERABLE component should be able to perform its imended function as atmospheric relief valves, etc.) or simply to perform
+
SG's in this plant condition.
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Further investigation into the background documentation supporting Technica 91015 revealed that the clarification was generated to address the minimum k
d condition) assumed in the uncontrolled boron dilution accident in the safety analys documentation did not address the Technical Specification 3.4.1.4 requiremen removal capability for removing decay heat. Discussions with the individua and concurrence of the clarification further supported the conclusion that decay hea s
< h /" " " '
.., c c
.,ot,,J 7' addressed in the 102 ft level determination of" loops titled."
ISEG notified the Technical Support department of the mis-interpretation of t problem to occur (e.g.. the Specification clarification and the potential for a more signific loss of the OPERABLE train due to n single failure could have potentially resu hcatup without the ability to transfer heat to the secondary). ISEG further new Technical Specification clarification of" loops tilled" based on an Engineerin removal capability. As a result of the ISEG' recommendations. Technical Sup Technical Specification clarificatien and generated this RER to obtain an eng conditions necessary to support use of two SG's for decay heat removal in the l
Mode 5.
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!~ nvestigatiom When the plant is being depressurized and cooled dow Prior to J
RCS depressurized and vented, and level is decreased in preparation for l
I RER l
mode 6 entry. both trains of RHR are required to be declared operable. T y
li l tion l
attempts to answer is "when are the plant conditions no longer adequate to i
f RHR to be declared through the SG*a as a method of decay heat removal, thus forcing the second tra n operable prior to proceeding with plant cooldown and depressurization."
Westinghouse WCAP 11086 documents actual temperature difTere ld i
and cold legs of the Diablo Canyon plant for all four loops during a Natura Comparison analysis wu performed and subsequently approv Vogtle's NRC SER section 5.4.7.5 and supple of a start-up test.
ii m temperaturc slightly less than Diablo Canyon's. Westinghouse en li l ti n the SG ensure sufficient natural circulation Ocw to preven h
i s that ill initiate in the may exist during shutdown conditions. The minimum temperature at wh f
SG's is 212*F. Adding the minimum AT of 50'F to 212*F results in a min 262'F that would be suffldent to maintain ade h
the natural circulation flow path must be avoided. therefore, t e pressur F tf h lowest pressure point (top of the SG tubes 224') must be above the RCS pressure at the top of the SG tubes is allow possibility of boiling in the core.
It is pouible that adequate heat transfer will occur when RCS pr i
f tion of the resultant than the saturation pressure for 262*F. How much les ld be il f lowcr RCS to SG required to prevent core boiling. The heat transfer ra h SG secondary would promote sufficient natural circulation to prevent core boiling. The 212*F such that reach boiling conditions necessitating RCS tempe hl t RCS i
dent. It is important to temperature and pressure that would adequately rem l
nario for the natural circulation process.
During a normal shut down for a refueling ou HR are not estimated time to reach saturation conditions in the reactor core durin bl ssume significantly greater than the 6 to 9 minutes shown graphically in l room that could be that sufficient time would exist for any manual operator actions outside implemented to mitigate a loss of all RHR. pressurizer m i
t of a tLhttA56WetRW. m
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differences between the core and he RCS fluid may be raised quickly to ensure that adequate temperature i
li of RCS the SG's may be reached in order to initiate and maintain natural ci
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t i
h Other prudent measures include maintaining: (1) a source of feed pressure control is an important po nt w en a ii h SG secondary appmpriate AFW pumps available, and (3) SG hlowdcwn capability. Mainta n ng t e RCS pressure.
i factor.
water temperature as low as possible through feed and bleed activitics could b The SG feedwater will boil and steam must be allowed to exit the SG's c i
i creases which the process. Secondary side pressure increases will resu h
b d cing j
ill also cause a the decay heat removal capability of the SO's. Seconda j
j bility of the natural circulation flow rate which will also serve to diminish the decay beat re j
l SG's, li An added complication to this phenomenon is the f
i d as condition has been experienced at VEGP as well as other plants and has mos gas accumulation in the Reactor vessel head. Easil executed op 2
3 i
and mitigating this phenomenon. Neither diagnostic i
li ill of solid plant pressure control will allow RCS pressure to be quickly raise h
l
.be driven back into solution. therefore abating any negative impact t ese g circulation flow.
The lowest pressure location in the primary side flow loops is at the top of il bl f RCS pressurc wide range pressure channels and idle RHR train discharge pressure readings ava f
indication during mode 5 plant operations. The oide range RCS instruments a l
I 0 - 3000 psig and are located at elevations that are significantly below th Potentially high reactor coolant temperatures prudent safety margins, i 4
inimum the order of 1.25% to 2.0%). and elevation head corrections necessitate that operatio dhions. When of 100 psig wide range pressure reading during natural circulation decay hea l
I d
i using the idle RHR train discharge pressure indicators the potential erro d be prevent confusion and provide maximum safety margin. the same m l
used when reading RHR gauges also.
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l A nuclear network question was sent to the industr i
1
{l) RCS pressurir.ed above removal via natural circulation only when the following 3 criteria are met:
100 psig. (2) loop stop valves wide open for the affected SG's. (3) 5 d
top of the tubes. (4) 100.000 gallons of feedwater available, and (5) associate operation. Fon Calhoun's Tech Spect specifically state that one f
8 l
steam generator and reactor coolant pump be operable. Numerous dis l
h (Bratdwood. Byron. Turkey Point. Sequoyah. Comanche Peak. Callaw l
plants were held. Most of these plants have ad AS&M d$hf%t M W F'.".5, j
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ocumenting specific RCS temperatures or SG secondary pressures nec i
i sufficient to prevent core boiling. Those plants that have operated in the pas d
All limit:. tion on RCS and SG configuration have initiated a review of these ope ili ith (representing 8 plants) of the utility representatives, as wcll as the Westing l can natur;l circulation technical issucc. agree that.long term natural circulation decay be tot occur without the ability to pressurize the RCS.. -
During the investigation of this RER. it was deter 1
G manways or of the way up the tube bundle leaving 20' of the tubes not submerged. There ar h ndholes between the 17% WR point and the top of the tube bundle. Th SG's with the tubes submerged in water is far sup j
i d
ater level reveal any detrimental etTects to outage scheduling or plant operations if the SG h t sink. This were required to be above the top of the tubes when relying on operability of a 3 2 as well as portion of the investigation applies to surveillance requirements 4.4.1.2.2 ide range level specification 3.4.1.4.1. The top of the SG tube bundle. elevation 224', corre reading of about 60%
When relying on the decay heat removal capability of the steam g h f ll wing criteria circulation of reactor coolant in mode 5. loops should b Ccnclusion:
are met:
b 60% WR. (3) one and letdown flow. (2) the relied upon SG's have their s li d upon SG?s. Altematively. RCS taking suction from the available CST and irpecting into the re e pressure can be maintained above 100 psig with pressure control v nt criteria number 1 above. During outage scheduling, considemtion should b l
bility availability (such as RCP's, steam dumps, and SG blowdown) such that the can be maximized.
Operations thould consider making ~ changes" to procedures th These changes would requirements 4.4.1.2.2 and 4.4.1.3.2 to require leve G
without imposing onerous limits on the Outage and Planning or Operations staff.
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