ML20197A082
| ML20197A082 | |
| Person / Time | |
|---|---|
| Issue date: | 06/26/2020 |
| From: | NRC/OCIO |
| To: | |
| Shared Package | |
| ML20197A080 | List: |
| References | |
| FOIA, NRC-2019-000253 | |
| Download: ML20197A082 (476) | |
Text
ATTACHMENT 7 Time Validation - Performance of SBO and Starting of Division 2 Diesel Generator (b )(5)
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ATTACHMENT 7 Time Validation - Performance of SBO and Starting of Division 2 Diesel Generator Page 2
ATTACHMENT 7 Time Validation - Performance of SBO and Starting of Division 2 Diesel Generator (b)(5)
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- : Case : Prob/Fre :Total % \Cut Set l Descri tion (b)(5)
Decay Heat Level (b)(5)
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HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSl *I EET (b )(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSHEET (b )(5)
HRA Worksheets for LPSD (b)(5)
Revised SPAR-H Worksheet*
- Revised based on updated guidance provided in INUEXT-10-18533, Revision 2, "SPAR-H Step-by-Step Guidance."
(b)(5)
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HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSHEET (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSHEET (b)(5)
URA Worksheets for LPSD (b)(5)
(b )(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSHEET (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERRO R WORKSH EET (b)(5)
URA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR II UMAN ERROR WORKSII EET (b )(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET
{b )(5)
HR.A Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR llllMAN ERROR WORKSII EET (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERROR WORKSH EET (b)(5)
HR.A Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERROR WORKSH EET (b)(5)
URA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR II UMAN ERROR WORKSII EET (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSHEET (b)(5)
HRA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR II UMAN ERROR WORKSII EET (b )(5)
H RA Worksheets for Ll'SD (b)(5)
HR.A Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR llllMAN ERROR WORKS II EET (b )(5)
HRA Worksheets for LPSD (b)(5)
ARA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR II UMAN ERROR WORKS II EET (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b)(5)
HR.A Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD C" O D 111 11\.* .._ 1\.1 t.'D D n D u 1n n v C', II V' l'.'T (b )(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b)(5)
HR.A Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSHEET (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b )(5)
HR.A Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD
!:PA R H IJMAN 11DIH)R Wf\D l!<-:H F.F.T (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERROR WORKSHEET (b )(5)
URA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b)(5)
HR.A Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSHEET (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b )(5)
URA Worksheets for LPSD (b)(5)
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HRA Worksheets for LPSD SPAR H UMAN ERROR WORKSHEET (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERROR WORKSHEET (b)(5)
URA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD
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URA Worksheets for LPSD Sl'AR HUMAN 1::RIWR WORKSIIEET (b)(5)
URA Worksheets for LPSD (b)(5)
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HRA Worksheets for LPSD SPA R H UMAN ERROR WORKS HEET (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERRO R WORKSH EET (b )(5)
URA Worksheets for LPSD (b)(5)
(b )(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b )(5)
HRA Worksheets for LPSD SPAR H UMAN ERROR WOR KSHl:ET (b)(5)
URA Worksheets for LPSD (b)(5)
(b )(5)
URA Worksheets for LPSD 4i.:P.i.\D 1-11 [, ,i..1 l<' llllllD \ Vf'IQl(_~ u-.:;-1:"'T' (b)(5)
HRA Worksheets for LPSD SNR HUMAN ERROR WORKSH EET (b )(5)
URA Worksheets for LPSD (b)(5)
URA Worksheets for LPSD 4i.:P.i.\D 1-11 [, , i..1 l<' llllllD \ Vf'IQl(_~ u-.:;-1:"'T' (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b )(5)
HRA Worksheets for LPSD (b)(5)
URA Worksheets for LPSD SPA R H UM AN ERROR WORKSHEET (b )(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b)(5)
URA Worksheets for LPSD (b)(5)
URA Worksheets for LPSD 4i.:P.i.\D 1-11 [, , i..1 l<' llllllD \ Vf'IQl(_~ u-.:;-1:"'T' (b)(5)
HRA Worksheets for LPSD SNR HUMAN ERROR WORKSH EET (b )(5)
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URA Worksheets for LPSD 4i.:P.i.\D 1-11 [, ,i..1 l<' llllllD \ Vf'IQl(_~ u-.:;-1:"'T' (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b )(5)
HRA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR llllMAN ERROR WORKSII EET (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b )(5)
HR.A Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD C" O D 111 11\.* .._ 1\.1 t.'D DnD u 1n n v C', II V' l'.'T (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b )(5)
HRA Worksheets for LPSD (b )(5)
HRA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b)(5)
URA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERRO R WORKSH EET (b)(5)
URA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR HUM AN ERROR WORKSHEE'I' (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b )(5)
URA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSHEET (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERROR WORKSHEET (b )(5)
URA Worksheets for LPSD (b)(5)
Punthlitl Change fifst top evem on ET to <OUMMV-FT>
Th~e ~re current~ 3 HEX injt;c:1ion method$. DQ I n<<d ta add mo,eJ Fi1 SD-CVS ET lo p e~n1 Add manual j1~ l'IOt dependent on electncal po wer) method toverit cont ainment
,., .. ,.;w, M itman Milman Milman Mitman ShooW I credit openirle primary c;ontainment .iirlodt aoJ a method to vent PC7 Mitman Add method to powerSRVs using 95bdieset using CPS 430l.01P004 , Modify A ; DENS. Mitman ShooW I credit 95b fire JX,1mp .is injection method? Mitman ShooW I modify ET to credit low prenure injection withot.rt depre:swrization lPfiOf to boilin,e]? This i5 OfllV fe.isibk if p~ures direa operat<< to e:stab1ish letdown path, which c;urrimtly we h;r,ie no evidence oft This would require second :M?t Mitm.in of HEPs with shorter time ~ ililb~.
ShooW offsite pow'1' non-JetO'lff'Y probabilTty be bned Ofl b.tttery Hfe or 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />? Mitman (b)(5) 10 RlMSit Div, 2 EOG non*retoYl!fV probilbility Mitman 11 Remit offsite power non~rec;overy prob.tbilitv Mitm.in (Qm:::::IM 12 13 14 Consider solYing all ET top el/fflt fTs usirlg succ.e:ss criteria Find lnue with RCIC support s'(itern FT A$k Bob Buell to thedt for model FT ren:imins ~ rors Mitman ICozak Milman I
___________________,. coml)fe t e JS Senshlvltv Cases: Mitman a SetHEf'stoEKelonva1ues b DeaeaseHE~byfactorof0.1 c Increased Ow. 2 EOG reCOVefV probab' tty d No FLD: credit and n<HHecO'lefV probabilities based on 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> e case using~M! dependent HEP for in)ectlon methods 1ns1ead of indep. HEPs 16 ' HEP AClS-XHE-XM-MDfl'R has a value ofSE-4 frorn at~power model. Checl: to~ lfthls Is appropriate for SO Mitman 17 Compare FLEX 0G FS/Fll/fM \'adues to Exek>n values Mitman 18 Compare FLEX diesel driven pump FS/FR/TM Ylll1UH to b.elonvalues Mitman l9 Add HEPs for FLEX dlsel driven pump traMponaUon and T&.M Mitman 20 FT: SD*SDC Make wre there ls. no uander to Altl"r SDC whldl 15 an artJf&ct of the Grand Gulf model Mitman Re*looti; at HEP tffles *or.1ilo1We; My re,c:Q llection ii that TTOC ii a boot 24 hoors at low reswre and about 10 houn at high 21 preswre (tti,is time delta makes sense becau~ Qf tfie Sow'1' heat c:.p.icity oilil ~1000 psig), The implic:.tion is that low pres:s\.lfe Mitm*n
~~~ will have about 24 to core untO'lff'Y while high pressure sequenc;e~ will have half the t ime,
""24 27 "29
,a
Notes Items 1 Division 1 electrical system powers outboard containment isol ation va lves. Div. 2 powers inboard valves.
Div. 3 to Div. 2 crosstie: The req uired lockout resets cannot be performed with AC and DC power (per discussion between SRI and licensee). AC power w ill be avai lable on Div. 3 if the EOG is ru nning. DC power on Div. 3 should be ava ila ble. However, DC power will be avail able on Div. 2 after t he Div. 2 battery depletes - this assu mes that FLEX 2 electrical has failed.
3 4
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9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
ET Top FT*
Name Top Logic Comments Quantification SD-SOC delet e term 1.00 SD-DEP system logic 0.31 SD-LPI system logic 1.00 SD-ALT-INJ delete term 0.39 SD-HPI delete term 0.73 SD-SPC-EXT delete term 0.64 SD-ALT-HEAT delete te rm 0.01 (b )(5)
SD-CVS delete te rm 1.00 ELEC_XTIE delete te rm 0.53
- all FTs qu antified after setting Flag Set = ETF-MF-LOOP Option s on settin g the ET Top logic " Process Flag" Delete Term System Logic {I)
Deveoped Event {W)
(b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERRO R WORKSHEET (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKS:HEET (b )(5)
URA Worksheets for LPSD (b)(5)
HRA Worksheets for LPSD SPAR II MAN ERROR WORKSHEET Laura's HEP (b)(5)
HRA Worksheets for LPSD SPA R HUMAN ERRO R WORKSH EET (b)(5)
..,.,.-:"-:-::":""_ _ _ _ _ _ _JH!!R!!.ALIW~1o;u:r:kksi!h~*P~Pts~cfifou:rJLJP'.,SSJJD~----------7 Laura's HEP (b)(5)
HRA Worksheets for LPSD Laura's HEP SPAR HUMAN ERROR WORKSHEET (b)(5)
HRA Worksheets for LPSD SPAR HUMAN ERROR WORKSH EET (b)(5)
HRAWn , fnr T o,;;:n (b)(5)
Laura's HEP
Note to requester: This document has been withheld in its entirety under FOIA Exemption 5
( deliberative process priviledge).
Human Failure Event (HFE) ID: SD-EPS-XHE-XM-NR01 H (b )(5) 03/04/2020
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Clinton EDG2 SOP Risk Summary 11/28/2018 Jeff Mitman The preliminary best estimate risk evaluation yielded a 3.8E-6 delta core damage frequency which is a white finding. This analysis was calculated using standard and well established NRG probabilistic risk assessment tools and methods and considered the as-built, as-operated plant.
We believe this estimate to be realistic. The preliminary risk evaluation considered perspectives provided by Exelon. In addition, sensitivity cases we're performed to evaluate the relationship between key input assumptions and the best estimate risk evaluation. Sensitivity analysis results showed that the finding could range from green to yellow.
The dominant sequence begins with a loss of offsite power followed by: A failure of the Division 2 (b)(5)[ .. .........E:r::r:i~rg~IJGY. Qie$eLGenerator.to.star~.--*********** --- I failure to depressurize the reactor, failure of all high pressure injection systems, and finally, failure to cross tie the functional Division 3 electrical distribution s stem to the Division 2 s stem.
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We look forward to additional insights from today's discussion. Insights gained will be evaluated to decide whether to perform additional risk analysis. It should be noted that re-evaluation would revisit fill assumptions and inputs and that the final risk result may increase or decrease.
03/04/2020
UNITED STATES NUCLEAR REGULATORY COMMISSION REGION Ill 2443 WARRENVILLE ROAD, SUITE 210 LISLE, ILLINOIS 60532-4352 June 7, 2018 MEMORANDUM TO: Charles Phillips, Project Engineer Division of Reactor Projects, Branch 1 FROM: Patrick L. Louden, Director IRA/
Division of Reactor Projects
SUBJECT:
SPECIAL INSPECTION TEAM CHARTER FOR INOPERABILITY OF THE CLINTON POWER STATION DIVISION 1 AND DIVISION 2 EMERGENCY DIESEL GENERATORS On Thursday, May 17, 2018, a non-licensed operator discovered the Division 2 emergency diesel generator (EOG) was inoperable due to the air receiver outlet valves being in the closed position. At the time of this discovery, the Division 1 EOG was inoperable and unavailable to complete planned outage maintenance on the Division 1 alternating current (AC) electrical power system. The licensee determined operations personnel failed to open the Division 2 EOG air receiver outlet valves when the EOG was returned to service on May 11 , 2018. The licensee subsequently removed the Division 1 EOG from service on May 14, 2018. Once the concurrent inoperability and unavailability of the Division 1 and Division 2 EDGs was identified, operations personnel opened the Division 2 EOG air receiver outlet valves to restore the EOG to an operable status.
The inoperability and unavailability of the Division 1 and Division 2 EDGs resulted in a loss of safety function for the onsite AC electrical power system and placed the Unit in an unplanned shutdown risk red condition for the electrical power key safety function. This condition also caused an unplanned shutdown risk orange condition for the decay heat removal key safety function due to the unavailability of safety-related electrical power to the primary and alternate decay heat removal systems.
Based on the deterministic criteria provided in Management Directive (MD) 8.3, "NRG Incident Investigation Program," the event met MD 8.3 criterion (d), in that there was a loss of safety function for the Division 1 and Division 2 EDGs. The event also met MD 8.3 criterion (h), in that the event raised concerns pertaining to operational performance in the areas of configuration control, risk management and oversight. The risk assessment resulted in an estimated Conditional Core Damage Probability (CCDP) range of E- 6 and put the event in the Routine Inspection/Special Inspection overlap region.
In addition to this event, Region Ill also noted the licensee's recent performance in the areas of configuration control, risk management and oversight. Between May 1 and May 13, 2018, three self-revealing events occurred indicating weaknesses in configuration control , risk management and oversight may be more widespread. The issues included:
CONTACT: Karla Stoedter, DRP 630- 829- 9731
Inability to Trip a Reactor Recirculation Pump Breaker - During activities to trip the pump breaker, the breaker would not trip. Although the licensee initially believed the breaker's failure to trip was due to circuitry issue, a subsequent review determined licensee personnel were unaware the breaker's control power configuration had changed from energized to de-energized due to planned maintenance on the Division 4 NSPS system.
Unexpected SCRAM Signal due to Maintenance Activities - On May 7, 2018, with one division of the instrument range monitoring system (IRMs) out of service, the licensee performed maintenance and testing on another IRM division which caused a SCRAM signal to be generated. The work instructions in use did not specify an order for disconnecting the test equipment used during this activity. In addition, operations and maintenance personnel did not recognize a SCRAM signal could occur based upon the order the test equipment was removed.
Failure to Verify Valve Position Prior to Operation Results in Equipment Damage - On May 9, 2018, operations personnel directed an equipment operator into the plant to relax the high pressure core spray minimum flow valve off of its seat. Based upon the direction provided, the equipment operator assumed the minimum flow valve was in the closed position and the valve needed to be opened to relax it off its seat. Neither the operations personnel providing the direction nor the equipment operator sent into the plant used configuration control information to validate the minimum flow valve's position. As the operator applied force and attempted to open the valve, the valve was forced into its backseat (due to being in the open position) and over torqued shearing the valve's stem.
Based on the deterministic and risk criteria in MD 8.3, the licensee's recent performance discussed above, and after consultation with NRR, Region Ill has decided to commence a Special Inspection on June 20, 2018. The Special Inspection will be led by you and will include Robert Murray and Jason Draper. In addition, Laura Kozak, RIii Senior Reactor Analyst, and Jeff Mitman, Senior Reliability and Risk Engineer, will assist the team as needed. The focus of the inspection is to gather information to determine the cause of the EOG event, understand the increased plant shutdown risk condition, and evaluate the licensee's immediate and planned corrective actions for the personnel and process weaknesses that led to the event. On a daily basis, the team should evaluate the need for increasing the scope of the inspection if conditions warrant.
The Team's charter is enclosed.
Docket No. 50---461 License No. NPF- 62
Enclosure:
Clinton Special Inspection Team Charter CONTACT: Karla Stoedter, DRP 630-829-9731
DRAFT CLINTON SPECIAL INSPECT ION TEAM CHARTER This special inspection team is chartered to assess the circumstances surrounding the concurrent inoperability and unavailability of the Division 1 and Division 2 emergency diesel generators (EDGs) during the 2018 Refueling Outage. Tile Special Inspection will be conducted in accordance with Inspection Procedure 93812, "Special Inspection." The special inspection will include, but is not limited to, the items listed below. This charter may be revised based on the results and findings of the inspection. The inspection results will be documented in NRC Inspection Report 2018050.
- 1. Develop a complete sequence of events related to the inoperability and unavailability of the Division 1 and Division 2 AC power systems from May 9 through May 17, 2018. The chronology should include plant mode changes, changes in the electrical power, decay heat removal and inventory control shutdown safety/risk areas. Draper, I'd like to include the thought processes of those involved in some of the decision making.
- 2. Understand the increased shutdown risk condition which existed when no emergency AC power sources were available for a period of approximately 3.5 days. Review the planned shutdown safety configuration compared to the actual configuration that existed.
Understand the licensee's ability to respond to and mitigate a loss of offsite power event given the unavailability of both onsite emergency AC power sources. Murray
- 3. Review the licensee's cause analysis efforts and determine if the evaluation's level of detail is commensurate with the significance of the problem. Phillips
- 4. Determine the probable cause(s) for the unavailability of the Division 1 and Division 2 EDGs during the 2018 refueling outage. All
- 5. Understand whether there were any deficiencies in operator training (both licensed and non-licensed operators) which contributed to the EOG unavailability and the failure to identify the condition across multiple operating shifts. Murray
- 6. Evaluate the licensee's compliance with, and adequacy of, procedural guidance for performing system alignments, controlling equipment configuration, performing equipment tag-outs and control room log keeping as it pertains to the cause(s) of the event. Draper
- 7. Evaluate licensee planned and completed corrective actions following the EOG ,event to the extent possible and assess if prior opportunities (e.g., surveillances, maintenance, and self or nuclear oversight assessments) existed to have identified the problem at an earlier point in time. Murray
- 8. Determine whether recent internal and external operating experience involving configuration control, risk management and oversig ht of activities were appropriately evaluated and determine the adequacy of any corrective actions planned or completed.
Phillips
- 9. Continually evaluate the complexity and significance of the event to determine if the circumstances warrant escalation of the inspection to an augmented inspection team.
Phillips Enclosure
- 10. Identify any lessons learned from the Special Inspection, and prepare a feedback form on recommendations for improving reactor oversight process (ROP) baseline inspection procedures. All Special Inspection Team Charles Phillips, Project Engineer, DRP, Special Inspection Team Leader Robert Murray, Senior Resident Inspector, Quad Cities Jason Draper, Health Physicist, DNMS Charter Approval I RA/ 6/5/18
~~-------- K. Stoedter, Chief, Branch 1, Division of Reactor Projects
______ /R_A_/_ _ _ _6_ / 6_/_18_ _ _ K. O'Brien, Director, Division of Reactor Safety
_ _ _ _ _.....;IR"""A'-"l________,;;6.;. ;/7. .'/-'-'18"----
- a. P. Louden, Director, Division of Reactor Projects ADAMS Accession Number: ML18158A170 2
/'\
U.S.NRC UNITED STATES NUCLEAR REGULATORY COMMISSION Protecting People and the Environment Phase 3 Risk Assessment Clinton Emergency Diesel Generator Division 2 Issue Clinton Units 1 Revision 0.0 C
Probabilistic Risk Assessment (PRA) Analyst: Jeff Mitman, Senior Reliability and Risk Analyst, NRR/DRA/APOB Region Ill Peer Reviewer Laura Kozac, Senior Reactor Analyst File Name: 8e1003a1-9069-4eb8-be32-58ccc50d01 b5.pdf 3/5/2020
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MD 8.3 Evaluation Decision Documentation for Reactive Inspection (Deterministic and Risk Criteria Analyzed)
PLANT: Clinton EVENT DATE: DETERMINISTIC CRITERIA 05/11/2018 EVALUATION DATE: 5/18/2018 Brief Description of the Significant Operational Event or Degraded Condition:
On May 9 at 1725, a clearance order for the Division 2 emergency diesel generator (EOG) was removed following a Division 2 bus outage. This clearance order directed the Division 2 EOG air reservoir outlet valves remain closed to prevent the Division 2 EOG from starting since the safety-related service water to the EDG remained out of service. Restoration of the Division 2 EOG and the reservoir isolation valves was tracked via a control room log entry. On May 11, the service water system was restored and the Division 2 EOG was declared available with operability occurring on May 12. Two days later, the Division 1 EDG was declared inoperable for planned maintenance. On May 17, an equipment operator discovered the Division 2 EOG had not been appropriately returned to an available and operable status because the air reservoir outlet valves remained in the closed position. This resulted in the licensee being in Mode 5 and Mode 4 without an operable EOG and a licensee unplanned red shutdown safety condition.
Y/N DETERMINISTIC CRITERIA N a. Involved operations that exceeded, or were not included in the design bases of the facility Remarks:
N b. Involved a majIor deficiency in design, construction , or operation having potential generic safety implications Remarks:
N c. Led to a significant loss of integrity of the fuel, primary coolant pressure boundary, or primary containment boundary of a nuclear reactor Remarks:
y d. Led to the loss of a safety function or multiple failures in systems used to mitigate an actual event (b)(S Remarks: I I (b )(5) 1_ . . . . I N e. Involved possilble adverse generic implications Remarks:
N f. Involved significant unexpected system interactions Remarks:
N g. Involved repetitive failures or events involving safety-related equipment or deficiencies in operations Remarks:
y h. Involved questions or concerns pertaining to licensee operational performance (b )(5)
Remarks'. 1 I (b)(5) 2
I CONDITIONAL RISK ASSESSMENT I
RISK ANALYSIS BY: L. Kozak RISK ANALYSIS DATE: May 18, 2018 3
Brief Description of the Basis for the Assessment (may include assumptions, calculations, references, peer review, or comparison with licensee's results):
(b)(5)
The following assumptions were made:
(b)(5) 4
(b)(5)
The estimated conditional core damage probability (CCDP) is _E-6_ and places the risk in the range of a special inspection and no additional inspection.
I RESPONSE DECISION I
USING THE ABOVE INFORMATION AND OTHER KEY ELEMENTS OF CONSIDERATION AS APPROPRIATE, DOCUMENT THE RESPONSE DECISION TO THE EVENT OR CONDITION, AND THE BASIS FOR THAT DECISION DECISION AND DETAILS OF THE BASIS FOR THE DECISION:
BRANCH CHIEF: Karla Stoedter DATE:
SRA: Laura Kozak DATE:
DIVISION DIRECTOR: Patrick Louden DATE:
5
DIVISION DIRECTOR: Kenneth O'Brien I DATE:
ADAMS ACCESSION NUMBER:
EVENT NOTIFICATION REPORT NUMBER (as applicable): EN 53409 Decision Documentation for Reactive Inspection (Deterministic-only Criteria Analyzed)
PLANT: Clinton I EVENT DATE: 5/1 1/20 18 I EVALUATION DATE: 5/18/2018 Brief Description of the Significant Operational Event or Degraded Condition: On May 9 at 1725, a clearance order for the Division 2 emergency diesel generator (EOG) was removed following a Division 2 bus outage. This clearance order directed the Division 2 EOG air reservoir outlet valves remain closed to prevent the Division 2 EOG from starting since the safety-related service water to the EOG remained out of service. Restoration of the Division 2 EOG and the reservoir isolation valves was tracked via a control room log entry. On May 11, the service water system was restored and the Division 2 EOG was declared available with operability occurring on May 12. Two days later, the Division 1 EOG was declared inoperable for planned maintenance. On May 17, an equipment operator discovered the Division 2 EOG had not been appropriately returned to an available and operable status because the air reservoir outlet valves remained in the closed position. This resulted in the licensee being in Mode 5 and Mode 4 without an operable EOG and a licensee unplanned red shutdown safety condition.
REACTOR SAFETY Y/N IIT Deterministic Criteria N Led to a Site Area Emergency Remarks:
N Exceeded a safety limit of the licensee's technical specifications Remarks:
6
N Involved circumstances sufficiently complex, unique, or not well enough understood, or involved safeguards concerns, or involved characteristics the investigation of which would best serve the needs and interests of the Commission Remarks:
Y/N SI Deterministic Criteria N Significant failure to implement the emergency preparedness program during an actual event, including the failure to classify, notify, or augment onsite personnel Remarks:
y Involved significant deficiencies in operational performance which resulted in degrading, challenging, or disabling a safety system function or resulted in placing the plant in an unanalyzed condition for which available risk assessment methods do not provide an adequate or reasonable estimate of risk.
(b )(5) ..... Remarks:J I
(b)(5)
RADIATION SAFETY Y/N IIT Deterministic Criteria N Led to a significant radiological release (levels of radiation or concentrations of radioactive material in excess of 10 times any applicable limit in the license or 10 times the concentrations specified in 10 CFR Part 20, Appendix B, Table 2, when averaged over a year) of byproduct, source , or special nuclear material to unrestricted areas Remarks:
N Led to a significant occupational exposure or significant exposure to a member of the publ ic. In both cases, "significant" is defined as five times the applicable regulatory limit (except for shallow-dose equivalent to the skin or extremities from discrete radioactive particles)
Remarks:
7
N Involved the deliberate misuse of byproduct, source, or special nuclear material from its intended or a uthorized use, which resulted in the exposure of a significant number of individuals Remarks:
N Involved byproduct, source, or special nuclear material, which may have resulted in a fatality Remarks:
N Involved circumstances sufficiently complex, unique, or not well enough understood, or involved safeguards concerns, or involved characteristics the investigation of which would best serve the needs and interests of the Commission Remarks:
Y/N AIT Deterministic Criteria N Led to a radiological release of byproduct, source, or special nuclear material to unrestricted areas that resulted in occupational exposure or exposure to a member of the public in excess of the applicable regulatory limit (except for shallow-dose equivalent to the skin or extremities from discrete radioactive particles)
Remarks:
N Involved the deliberate misuse of byproduct, source, or special nuclear material from its intended or authorized use and had the potential to cause an exposure of greater than 5 rem to an individual or 500 mrem to an embryo or fetus Remarks:
N Involved the fai lure of radioactive material packaging that resulted in external radiation levels exceeding 10 rads/hr or contamination of the packaging exceeding 1000 times the applicable limits specified in 10 CFR 71.87 Remarks:
N Involved the failure of the dam for mill tailings with substantial release of tailings material and solution off site Remarks:
8
Y/N SI Deterministic Criteria N May have led to an exposure in excess of the applicable regulatory limits, other than via the radiological release of byproduct, source, or special nuclear material to the unrestricted area; specifically
- occupational exposure in excess of the regulatory limits in 10 CFR 20.1201
- exposure to an embryo/fetus in excess of the regulatory limits in 10 CFR 20.1208
- exposure to a member of the public in excess of the regulatory limits in 10 CFR 20.1301 Remarks:
N May have led to an unplanned occupational exposure in excess of 40 percent of the applicable regulatory limit (excluding shallow-dose equivalent to the skin or extremities fronn discrete radioactive particles)
Remarks:
N Led to unplanned changes in restricted area dose rates in excess of 20 rem per hour in an area where personnel were present or which is accessible to personnel Remarks:
N Led to unplanned changes in restricted area airborne radioactivity levels in excess of 500 DAC in an area where personnel wer,e present or which is accessible to personnel and where the airborne radioactivity level was not promptly recognized and/or appropriate actions were not taken in a timely manner Remarks:
N Led to an uncontrolled, unplanned, or abnormal release of radioactive material to the unrestricted area
- for which the extent of the offsite contamination is unknown; or,
- that may have resulted in a dose to a member of the public from loss of radioactive material control in excess of 25 mrem (10 CFR 20.1301 (e)); or,
- that may have resulted in an exposure to a member of the public from effluents in excess of the ALARA guidelines contained in Appendix I to 10 CFR Part 50 Remarks:
N Led to a large (typically greater than 100,000 gallons), unplanned release of radioactive liquid inside the restricted area that has the potential for ground-water, or offsite, contamination Remarks:
9
N Involved the failure of radioactive material packaging that resulted in external radiation levels exceeding 5 times the accessible area dose rate limits specified in 10 CFR Part 71, or 50 times the contamination limits specified in 49 CFR Part 173 Remarks:
N Involved an emergency or non-emergency event or situation, related to the health and safety of the public or on-site personnel or protection of the environment, for which a 10 CFR 50.72 report has been submitted that is expected to cause significant, heightened public or government concern Remarks:
SAFEGUARDS/SECURITY Y/N IIT Deterministic Criteria N Involved circumstances sufficiently complex, unique, or not well enough understood, or involved safeguards concerns, or involved characteristics the investigation of which would best serve the needs and interests of the Commission Remarks:
N Failure of licensee significant safety equipment or adverse impact on licensee operations as a result of a safeguards initiated event (e.g., tampering).
Remarks:
N Actual intrusion into the protected area.
Remarks:
Y/N AIT Deterministic Criteria N Involved a significant infraction or repeated instances of safeguards infractions that demonstrate the ineffectiveness of facility security provisions Remarks:
N Involved repeated instances of inadequate nuclear material control and accounting provisions to protect against theft or diversions of nuclear material Remarks:
N Confirmed tampering event involving significant safety or security equipment Remarks:
N Substantial failure in the licensee's intrusion detection or package/personnel search procedures which results in a significant vulnerability or compromise of pliant safety or security Remarks:
10
Y/N SI Deterministic Criteria N Involved inadequate nuclear material control and accounting provisions to protect against theft or diversion, as evidenced by inability to locate an item containing special nuclear material (such as an irradiated rod, rod piece, pellet, or instrument)
Remarks:
N Involved a significant safeguards infraction that demonstrates the ineffectiveness of facility security provisions Remarks:
N Confirmation of lost or stolen weapon Remarks:
N Unauthorized, actual non-accidental discharge of a weapon within the protected area Remarks:
N Substantial failure of the intrusion detection system (not weather related)
Remarks:
N Failure to the licensee's package/personnel search procedures which results in contraband or an unauthorized individual being introduced into the protected area Remarks:
N Potential tampering of vandalism event involving significant safety or security equipment where questions remain regarding licensee performance/response or a need exists to independently assess the licensee's conclusion that tampering or vandalism was not a factor in the condition(s) identified Remarks:
I RESPONSE DECISION I
USING THE ABOVE INFORMATION AND OTHER KEY ELEMENTS OF CONSIDERATION AS APPROPRIATE, DOCUMENT THE RESPONSE DECISION TO THE EVENT OR CONDITION, AND THE BASIS FOR THAT DECISION DECISION AND DETAILS OF THE BASIS FOR THE DECISION:
11
BRANCH CHIEF: Karla Stoedter DATE:
SRA: Laura Kozak DATE:
DIVISION DIRECTOR: Patrick Louden DATE:
DIVISION DIRECTOR: Kenneth O'Brien DATE:
ADAMS ACCESSION NUMBER:
EVENT NOTIFICATION REPORT NUMBER (as applicable):
Distribution: (to be inserted by division/branch secretaries) 12
Clinton Shutdown Model Assumptions
- Time to boil (TTB) = 4.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, based on Exelon document CL-SDP-010 Rev. 1
- Time to core uncover (TTCU) = 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if reactor is maintained atmospheric 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> if pressure rises to safety relief valve lift setpoints, based on Exelon document CL-SDP-010 Rev. 1
- Core uncovery is the normal at-power surrogate for core damage. During shutdown, core damage is expected between 1/3 and 2/3 core height which is somewhat after core uncovery, therefore, using core u ncovery as a surrogate for core damage is conservative.
- Unavailable and non-recoverable equipment due to test and maintenance (T&M):
o EOG lA (note 4160v AC bus lAl is energized and available as long as offsite power is available - because the associated EOG is unavailable, this bus will de-energize on loss of offsite power) o 480v AC bus lA o 480v AC bus A o NSPS 120v Power distribution panel bus A o 125v DC battery charger lA (which is feed from aux. building MCC lAl)
- Assumed available equipment o 480v AC aux. building bus 1L o 480v AC aux. building bus lM o 480v AC aux. building bus 10 o 480v AC aux. building bus lE (feed to 125v DC battery charger lF) o 125v DC battery charger lF (feed from 480v AC aux. building bus lE)
- According to drawing E02-1DC06 (125v DC & uninterruptible power supply systems) the normal feed to 125v DC bus lA is via battery charger lA. Per the licensee, this battery charger was not available due to T&M. Per the same drawing, the backup supply to 125v DC bus lA is from swing battery charger lDCllE from aux. building 480v MCVC lE (1AP28E). Per drawing E02-1AP03 (electrical load diagram), the 1DC25E battery charger is on 480v AC aux. building bus (b)(5) .... .lR. .UAPl4EJ,I ............. ------ !
(b)(5) -----ti- _ __ . . . .---------
- The at-power Clinton SPAR model has basic event (BE) failure probabilities for many of the valves that need to be manipulated by the FLEX procedures. These BE failure probabilities are based on data which include failure to open or close based on AC or DC power being available to operate the valve. Durin the ELAP condition electrical ower ma or ma not be available to (b)(5) ...... . ___________.ope.rate the valve* ...
(b)(5)
(b)(5) * ...... .......... _______
1 Without electrical power these contributions to the failure probability are not possible. This should lower the valve failure probabilities in the model. However, the valves can still be opened manually by an equipment operator (EO) at the valve operator without (b)(5)
High level guidance provided by 4306.01P017 Strategy Support Core Cooling Containment Spent Fuel Pool 1
- Lineup FLEX generator to Division 1 or 2 480
- Run available ECCS waterleg pumps
- Set Primary Containment Same as Mode 1,2,3 VAC per 4306.0lPOOl FLEX Elect rical
- Pressurize and run RCIC
- Establish suppression pool (makeup, ventilate)
Connections
per 4306.01P002 FLEX UHS Water Supply
- Open an SRV Procedure List Revision Procedure Current Title Controlling Comments Number Revision during PD 4006.01 Loss of SOC Sc Sc 4200.01 Loss of AC Power 2Sa 2Sa 4200.01C002 DC Load Shed during a 580 Sa Sa 4303.01P023 Cross-Connecting Div. 3 DG 2b 2b to Div1(2)ECCS Electrical Busses 4306.0lPOOl FLEX Electrical Connections Od Od Directors operat or to DC load shed per 4200.01C002 4306.01P002 FLEX UHS Water Supply Oe Oe Takes about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to perform per 4306.01P017 4306.01P003 FLEX SPC 4306.01P004 Makeup to RCS Strategy 1 (to be used in CSD) below steps are stipulated in 4306.0lPOl7:
- Run ECCS waterleg pumps
- Makeup to using this procedure
- "Take action to establish primary containment integrity."
- Consider using ECCS waterleg pumps for RPV injection using power from FLEX DG Supplies guidance on using 3 strategies depending on POS. For CSD, directs operator t o Strategy 1 (see table above) 4411.06 Emergency Containment 6b 8/5/18 ??
Venting, Purging, and Vacuum Relief
Table X S1 ,f D,
- -- ----- -- --- -- - - - ----- -- -- HRAR, M ean Mean Total Time Time Human Error Event Description Procedure Diagnosis Action Mean Needed Available HEP HEP HEP SD-XHE-XM-XTIE Cross Tie Div. 3 and Div. 2 Electrical 4303.01P023 4.0E-2 6.0E-1 6.4E-1 Operator Fails to Setup and Run FLEX SD-XHE-XM-FELEC 4306.0lP00l 2.0E-2 2.3E-1 2.SE-1 DG and Electrical Distribution Operator Fails UHS Water Supply using SD-XHE-XM-FUHS 4306.01P002 2.0E-3 l.lE-1 l.lE-1 FLEX Operator Fails Suppression Pool SD-XHE-XM-FSPC 4306.01P003 l.0E-3 2.3E-1 2.3E-1 Cooling using FLEX Injection into RCS using FLEX Diesel SD-XHE-XM-FRCS Driven Pumps (4306.01P002 Sections 4306.01P004 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 2.0E-3 l.lE-1 l.lE-1 4.3 and 4.4)
SD-XHE-XM-DCLS Operator performs DC Load Shed 4200.01C002 lhour 4.0E-2 2.0E-2 6.0E-2 Operator Fails to Perform Firewater SD-XHE-XM-FWS ? 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 10 hours l.2E-1 Injection into RCS Operator Fails to Operate RCIC during SD-XHE-XM-FRCIC ? 2.0E-3 7.SE-1 7.SE-1 ELAP from Shutdown Operator Fails RCS Injection using FLEX 4306.01P004 SD-XHE-XM-FINJ 1 Hour 2E-3 2E-3 4E-3 SPC (4306.01P004 Section 4.1) Section 4.1 Manually Venting of Containment with CPS >24 FC-XHE-XM-MCV 4E-3 2E-4 4.2E-3 1FC012A & B 4303.0lP00l Hours SD-XHE-XM-ISDC Isolate SDC after LOSDC 4006.01
FLEX AC Electrical Fault Tree FLEX Electrical System FLEX-ELEC FLEX Diesel Generators FLEX Bus Equipment Failures ACP-FLEX-BUS FLEX-ELEC4 2.29E-05 Operator Fails to Setup and Run FLEXDG and Electrical Distribution SD-XHE-XM-FELEC FLEXDiesel l(permanentlyinstalled) FLEX Diesel 2 (portable) 3.20E-01 FLEX Electrical Connectio n Fails due to Design or Construction FLEX-ELEC41 FLEX-ELEC42 FLEX-ELEC-CONNECT S.00E-02 CCF of FLEX Diesel Generators 1 and 2 to Run FLEX Diesel Generator 1 Fails to Run FLEX Diesel Generator 2 Fails to Run EPS-FDGN-CF-FR 2.37E-03 EPS-DGN-FR-FDGl EPS-DGN-FR-FDG2 CCF of FLEX Diesel Generators 1 and l.S0E-01 l.S0E-01 2 to Start FLEX Diesel Generator 1 Fails to FLEX Diesel Generator 2 Fails to Start Start EPS-FDGN-CF-FS l.lSE-05 EPS-DGN-FS-FDGl l.20E-03 FLEX Diesel Generator 1 Unavailable EPS-DGN-FS-FDG2 l.20E-02 FLEX Diesel Generator 2 Unavai lable u
because of Test or Maintenance because of Test or Maintenance EPS-DGN-TM-FDGl EPS-DG N-TM-FDG2 1.48E-02 1.48E-02 u FLEX Diesel 2 (portable) Fails due to ImproperTransport or Setup EPS-DGN-XR-FDG S.00E-02 u
FLEX Suppression Pool Cooling Fault Tree FLEX Suppress ion Pool Cooing FSF I
I I I I FSPumps NotAvailable RHRHeatExchangers NotAvailable FLEX Electrical System CCF OF SF MOPS TO RUN FLEX*ELEC SF*MOP-CF*FR FFC2 FFC8 External 9.SIE-07 I
PUMP A IS UNAVAILABLE y
I PUMPB IS UNAVAILABLE y
CLINTON FLEX SPC LOOP B I S SD-FUHS FLEX UHS CCF OF SF MOP'S TO START SF*MOP*CF*STRT External 4.58E*06 UNAVAILABLE FSPC-B 6 SF COOLING SUCTION MOV F004 FFC64 FFC73 External SF*MOV*CC*F004 T 7 CLINTON FLEX SPC LOOP A IS 8.16E*04 UNAVAILABLE SF COOLING SUCTION Manual F003 FSPC*A Suppression Pool Cleant.p ard Suppress ionPoo I Cleant.p ard External Transfer MDP lA FAILS TO START Transfer MOP 1B FAILS TO START SF*VLV-CC*F003 SF*MOP*FS*IA SF*MOP*FS*lB 6 8.16E*04 SF COOLING Olscharge AOV F011 1.09E-03 1.09E-03 Suppress loIn Poo l Cleaiw ard Suppress loin Pool Cleaiw ard Trans fer MOP l A FAILS TO RUN Transfer MOP 1B FAILS TO RUN SF*AOV-CC*FOll 7.55E-04 SF-MOP-FR-IA SF*MOP*FR-1B SF COOLING Valve F041 9.00E-05 9,00E-05 SF MDP6A OISCHARGECH ECK SF MOP 6B DISCHARGE CHECK VALVE FAILS TO OPEN VALVE FAILS TO OPEN SF*MOV*CC-F041 8.16E*04 SF*CKV*CC*6A SF*CKV-CC-66 Operator Fails Suppressi<>n ll:>ol 9.24E*06 9.24E*06 Cooling using FLEX SFMDP IAUNAVAILABLEDUETO SF MDPIB UNAVAILABLEDUETO TEST AND MAINTENANCE TEST AND MAINTENANCE SD*XHE* XM-FSPC 3.02E*Ol SF*MDP*TM*lA SF*MDP*TM*IB FLEX Electrical Connection Falls 4.56E*03 4.56E*03 SF COOLING Dlscharge MOVFOIOA SF COOLING 0Ischa rge MOV FOlOB FLEX*ELEC*CONNECT 5.00E*02 SF-MOV-CC-FOl<l'\
8.16E-04 SF*MOV-CC-FOIOB 8.16E*04 u u u
FLEX Ultimate Heat Sink System Fault Tree
,~ --FL....E_X_U_H__S_S_ys- t-em
- (4
_3__
0_6.~0-l P--0-02
__)_,
SD-FUHS FLEX Engine Driven Pumps SSWA TIE TO PSW MOV SSW 14A FAILS TO CLOSE SSW-MOV-OO-SSW14A SD-FUHS! 8.16E-04 Operator Fails to Setup and Run FLEX Ult imate Heat Sink System (4306.01P002)
SD-XHE-XM-FUHS FLEX Pump 1 Fails FLEX Pump 2 Fails 1.l0E-01 FLEX PUMPS FAIL FROM COMMON CAUSE TO RUN SD-FUHS10 SD-FUHS11 FLEX-EDP-CF-FR 6.12E-03 FLEX PUMPS FAIL FROM COMMON CAUSE TO START FLEX ENGINE DRIVEN PUMP 1 FAILS FLEX ENGINE DRIVEN PUMP 2 FAILS TO RUN TO RUN FLEX-EDP-CF-FS 2.90E-04 FLEX-EDP-FR-1 FLEX-EDP-FR-2 FLEX Diesel Driven Pump Connectio n 2.00E-01 2.00E-01 Fails due to Design or Construction FLEX ENGINE DRIVEN PUMP 1 FAILS FLEX ENGINE DRIVEN PUMP 2 FAILS TO START TO START FLEX-EDP-CONNECT 5.00E-02 FLEX-EDP-FS-1 FLEX-EDP-FS-2 FLEX Manifold Iso latio n Valve Fails l.00E-02 l.0OE-02 Closed u u FLEX-MV-CC-1XF003 4.59E-04 FLEX Pipe Manifold Isolation Valve to SXDiv.1 or 2 Fails Closed FLEX-MV-CC-1XF001C 4.59E-04 FLEX Water Injection to SX Valve Div. 1 o r 2 Fails Closed SSW-MV-CC-SXF354 4.59E-04 u
FLEX Suppression Pool Cooling Injection to RCS Fault Tree FLEX Suppression Pool Cle<l"4)
Inject into RCS (4306.01P004 Section 4.1)
FLEX*SPC-INJ I
I I I Operator Fails RCS Injectio n using FLEX Suppress ion Poo l Cleanup ard FLEX Injection Paths Fai l FLEX SPC (4306.01P004 Sectio n 4.l) Transfer SD -XHE*XM*FINJ FLEX*SPC 2.20E-02 External FLEX-SPC-INJ2 LPCI I NJECTION MOVS RHR 42A,B,C FAIL FROM COMMON CAUSE 6 y I
RHR-MOV-CF-F042 FLEX Injectin Pat h via Train A FLEX Injectin Pat h via Train B 3.57E-06 LPCI CKVS 41 A,B,C FAIL FROM COMMON CAUSE FLEX-SPC-INJ20 FLEX-SPC* INJ21 RHR-CKV-CF-F041 6.07E-08 H H u RHR A MOV 27A FAILS TO OPEN RHR A MOV 278 FAI LS TO OPEN RHR* MOV-CC* F027A RHR*MOV-CC* F027B 8.16E-04 8.16E-04 LPCI TRAIN A INJECTION MOV LPCI TRAIN B INJECTION MOV RHR42A FAILS TO OPEN RHR42B FAILS TO OPEN RHR-MOV-CC-F042A RHR*MOV*CC-F0428 8.16E-04 8.16E-04 LPCI INJECTION CKV F041 A FAILS LPCI INJECTION CKV F04 1B FAI LS TO OPEN TO OPEN RHR* CKV-CC-41A RH R*CKV-CC-41B 9.24E-06 9.24E-06 0 0
Electrical Cross Tie between Div. 3 and Div. 2 Fault Tree Electrical Connection Div. 3 to Div. 2 ELEC_XTIE CLINTON DIVISION III AC POWER Operator Fails to Establish Div . 3 to SYSTEM FAULT TREE Div. 2 Electrical Cross ne ACP-4KVBUS- 1Cl SD-XHE-XM-CROSSTIE External 2.?0E-01 CLINTON DIVISION II AC POWER Div. 3 to Div. 2 Cross ne Fails due to SYSTEM FAULT TREE Cross ne Design ACP-4KVBUS-1B1-XTIE XTIE-ELEC-CONNECT External 2.00E-02 6 u
Division II AC Power Electrical for Cross Tie to Division Ill Fault Tree CLINTON DIVISION II AC POWER SYSTEM FAU LT TREE Cross Tie ACP*4KVBUS*1Bl*XTIE I
I I I 4.1 KV BUS FAILURE FROM SBSMIC FAILURE TO RECOVER BREAKER 4160 V DIVISION II BUS (!Bl)
EVENT CCF DURJNG BATTERY LIFE HARDWARE FAILU RES ACP-4KV-EO ACP*BAC*LP* lBl External ACP*4KVBUS-1Bl *XTIE4332 2.29E*0S FAILURE OF DN2 SWITCHGEAR COOLING
~ u HVC*SWGR*DIV2*CIJOL I I DC BA TTEREIS FAILURE FROM CCF OF 125VDC BATTERYS (3)
External SEISMIC EVENT CLINTON DIVISION II 125 voe POWER IS UNAVAILABLE DCP-BAT-EO DCP-BAT-CF*ALL Externa l 3.85E-08 DCP* 125V-1B*LT Externa l 6 FAILURE OF DIVISION ll 125VDC BATTERY 6 DCP*BAT*LP* lB 7.97E-06 FAILURE OF CIRCUIT BREAKER 201Bl TO OPEN (RAT)
ACP*CRB*CC*201Bl 2.49E*03 CCF OF CIRCUIT BREAKERS 201Al
& 201Bl TO OPEN ACP*CRB*CF-201 4.13E*05 FAILURE OF CIRCUITBREAKER 221Bl TO CLOSE ACP-CRB-OO-221Bl 2.0SE-03
Division Ill AC Power Fault Tree CUH10N DMSION m I< POWm SYSTtM FAULT 'TREE ACMICV8US-l0 LOSS OF POWER 104160V AC BUS 4160V 0MSJON Ill BUS.(IC1)
HAJWWAN.FA.llUA.ES ACl4KV8US-1Cl-1 .......,
ACP-*U.:V OFfSITE POWER.FROM THE ERAT [S U~YAJL/8.£ R&\UGNMENiFRON AATTO EAAT HOUSE EV8H
- LOSS OF OFFSITE HOUSE EVENT
~.alteCICJP e,~';-:i~~LO O ~ P ~ - - - ----i LOS'S OF EM ER.Ge.ICY RE~RY E LOSS Of RESERVE AUXll.lARY AUXILlARYTRANSFORM ER TRAN SRJRMER HE-lERAi f'-H~~~I.AA~T~ - - - - - - - - - l N IK ~* ~* IK ~ ---,..--------<
DC BATTERElS fol,JLURE FROM CCF OF l25vtlC 6Al"l'aYS {3)
SUSMICE\'SNT DC~~T ~DCP
=-~~ T~-C~F--All.=---------1 Elclerrel 3.BSE-08
>---------------1 FAR.URE OF DlYISlO N m 12SVOC BJ, fTERY FAlLURE OF CIRCt.lITBREAKfR ZOICl TO Of'EN(RAn ACP-CRB -CC-ZO ICI 2.49£.03 fAJLUII.E OfCOO:UJT BREAAER 22lC1TOCI.OSE 2..0SE-OJ
Alternate Heat Removal Fault Tree PROVIDE AL TERNATE HEAT REMOVAL PATH SD -ALT-HEAT I
I I I PCSORRWCU HOUSE EVENT - STATION OPERATOR FAILURE TO BLACKOU T EVEN TS REMOVE HEAT USING AL T SYS HE-SBO SD-XHE-XM-ALT-HEAT SD-AL T-HEAT2 False 1.00E-03 y 0 HOU SE EVENT
SYSTEM (U NDEVELOPED )
RWC-SYS-UD-HW SD-A LT-HEAT02 1.00E-02 H u FAILURE OF STEAM HOUSE EVENT
- LOSS OF CONDENSING FUNC TION OF OFFS ITE POWER IE HAS D~C ---.. ~---
PCS-STM HE-SD-LOOP External False 6 SD OPERATING MOOE 5 HE-SD-MODES False u
Clinton re-SERP Pre-briefing Questions 02-17-2019 J. Mitman (b )(5)
(b)(S)
(b)(5)
(b)(5)
Clinton Shutdown SPAR model (b )(5)
(b)(5)
Summary from Special Inspection Report (b)(5)
(b )(5) 2
4 (b)(5) 5
<D (b)(5) 7
(b)(5) 8
(b)(5) 9
(b)(5) 10
(b)(5) 11
(b)(5) 12
(b)(5) 13
(b)(5) 14
(b)(5) 15
(b)(5) 16
(b)(5) 17
(b)(5) 18
(b)(5) 19
(b)(5) 20
(b)(5) 21
(b )(5) 22
(b)(5) 23
(b)(5) 24
(b)(5) 25
(b)(5) 26
(b)(5) 27
(b)(5) 28
(b)(5) 29
(b)(5) 30
(b)(5) 31
(b )(5) 32
(b )(5) 33
PSFs that are assumed to be other than Nominal PSF Setting SD-XHE-XM-FRCS - Fail RPV inject with FLEX pumps Obvious Diagnosis Complexity (Diagnosis)
Moderate Complexity (Action)
Low Experience/Train ing (Action)
Poor Ergonomics (Action)
PSFs assumed correctly. No errors or omissions in report. PSFs not described because this is the less preferred FLEX injection method and is not currently important to the overall results.
SD-XHE-XM-DCLS - Fail to load shed Moderate Complexity (Diagnosis)
Poor Ergonomics (Action)
PSFs assumed correctly. No errors or omissions in report. No assumption on HEP documented because this HEP is not currently important to the overall results .
SD-XHE-XM-FRCIC - Fail to operate RCIC Obvious Diagnosis Complexity (Diagnosis)
PSFs assumed correctly . No errors or omissions in report. Assumption states that HEP is dominated by action .
FC-XHE-XM-MCV - Fail Manual containment venting Extra Time (D iagnosis)
>=5x Time (Action)
Moderate Complexity (Diagnosis)
PSFs assumed correctly. No errors or omissions in report. PSFs not described because this HEP is not currently important to the overall results .
SD-XHE-XL-ELAP - Fail to recover Electrical Moderate Complexity (Action)
PSFs assumed correctly. Omission in description of PSFs. Will change report to add moderate complexity.
Values of the HEP correct in assumptions, table 2 and the fault tree .
Observations on Division 3 to Division 1 or Division 2 cross-tie
- Action does not appear to be a reliable means to recover decay heat removal in scenario of interest (SBO, HPCS providing injection/inventory control, no decay heat removal)
- HPCS must be stopped to align the cross-tie, putting the plant in a condition with no injection.
- HRA analysis estimates 2 to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to install cross-tie based on a walkdown. Allowable time not documented in HRA analysis. Based on SRA question, licensee estimates 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> available based on MAAP evaluation.
- HRA analysis focuse*d on providing power to Division 1 for operation of an RHR and SX pump. Division 3 DG is not large enough to power HPCS, RHR, and SX at the same time, requiring operators to manage loads (doesn't appear to be evaluated in HRA, is practiced in simulator?)
- Licensee statement that many of the actions can be achieved on the receiving bus with no impact on HPCS. This conflicts with the procedure that states "Steps in this procedure must be performed in order to avoid the risk of personnel injury or equipment damage."
- Licensee statement that this procedure could be used to power containment vent paths.
HRA analysis has the following statement: "Based on crew interview, operators question the value of this action. Use of this procedure could result in a loss of HPCS injection.
Containment venting is not available without Division 1 and Division 2 AC power. The utility has a policy of verbatim compliance to procedures." The procedure provides instructions to power either Division 1 or Division 2. If both divisions are needed for containment venting then this procedure will not support containment venting for decay heat removal.
- Training appears to be very limited. The licensee provided a presentation that provides a reference to the procedure, shows the line-up to be achieved, with an overview (not detailed) of the actions necessary. Is this the training that is provided every two years?
- Procedure was complex. Reference to Figure 3, step 1.2 did not appear the same in the field.
Note to requester: The document on this page and the next page are notes from a call between NRR and Clinton on October 15, 2018 that are being withheld in their entiety under FOIA Excemption B5 (deliberative process priviledge).
(b)(5)
(b )(5)
Clinton Power Station White Finding for Multiple Emergency Diesel lnoperability Key Messages
- On April 1, 2019, the NRC issued NRC Inspection Report No. 05000461/2018092, (ML19092A212) documenting a final significance determination of White for failing to accomplish activities affecting quality in accordance with multiple procedures and consequently operating the plant in violation of Title 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," and the plant's Technical Specifications. This finding moves Clinton to Column 2 of the Action Matrix.
- The NRC took into consideration: information developed during a Special Inspection, the information provided at the regulatory conference, and the supplemental information that Clinton provided.
- The NRC noted that this was a complex shutdown significance determination.
NRC Inspection Report No. 05000461/2018092 documents a number of areas of disagreement between the NRC analysis and licensee assertions and provides rational for the NRC conclusions.
Facts
- As a result of several human performance errors the station's Division 2 Emergency Diesel Generator (EOG) was inoperable and unavailable for over 6 days without the licensee's knowledge. Both Division 1 and Division 2 EDGs were inoperable and unavailable for over 3 days, May 14 through May 17, 2018, which was not allowed per Technical Specification (TS) 3.8.2. NRC Special Inspection Report 05000461/2018050 dated August 23, 2018 (ML18235A170) documents this apparent violation and that the condition was a result of the licensee failing to follow multiple equipment config uration control procedures. NRC Inspection Report 05000461 /2018051 dated October 15, 2018, (ML18289A436) documents the preliminary White significance of the finding.
- Clinton Power Station has been in Column 2 of the Action Matrix since July 1, 2017. A White finding associated with the Division 1 EOG room ventilation fan was identified in the 3 rd quarter of 2017 and cleared by IP95001 inspection in the 2nd quarter 2018. A White finding associated with a Division 3 shutdown service water (SX) pump failure was identified in the 4 th quarter of 2017 and cleared by IP95001 inspection in the 4 th quarter of 2018. The start date of the current White finding is assigned to 3rd quarter of 2018 in accordance with the date of the Special Inspection Report.
3Q 2017 4Q 2017 1Q 2018 2Q 2018 30 2018 4Q 2018 1Q 2019 2Q 2019 White 1 White 1 White 1 White 1 White 2 White 2 White 2 White 2 White 2 White 3 White 3 White 3 White 3
- Clinton Power Station's End of Cycle Assessment letter noted a return to column 1 on November 28, 2018 with a caveat that there was a preliminary White finding in process.
- Subsequent to the final significance determination of White, a FOIA request was submitted to the agency, by a lawyer who attended the November 2018 Regulatory Conference, requesting all information related to this finding.
Proposed/Possible New AC Power Recovery FT and ELAP NRP (b)(5)
(b)(5) 9 03/05/2020
(b)( 5) 10 03/05/2020
Human Failure Event (HFE) ID: SD-EPS-XHE-XM-NR01 H (b)(5) 03/05/2020
(b )(5) 2 03/05/2020
(b)(5) 3 03/05/2020
(b)( 5) 4 03/05/2020
(b)( 5) 5 03/05/2020
(b)(5) 6 03/05/2020
(b )(5) 7 03/05/2020
(b)(5) 8 03/05/2020
(b )(5) 9 03/05/2020
(b )(5) 10 03/05/2020
From: Kichline, Michelle Sent: Thu, 25 Oct 2018 18:39:30 +0000 To: Mitman, Jeffrey
Subject:
RE: Re-evaluation of HFE for EDG non recovery - Clinton I have some questions:
- When the EOG fails to start, how many alarms related to the EOG failure will annunciate in the MCR? Is there a general EOG trouble alarm? Where do the MCR alarms point the operator?
- When are the crews trained to go to ELAP? The definition of ELAP presented in the LOAC procedure very clearly states that there needs to be a BDBEE to declare an ELAP, so I don't see why a LOOP would result in a declaration of an ELAP without some severe external stuff going on. However, the LOAC procedure doesn't get any more helpful if they don't declare an ELAP because they are still going to load shed.
My evaluation, based on 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to diagnose the reason for the EOG failure and correct it:
Relevant Diagnostic Performance Shaping Factors (PSF)
- Time: Extra time (.1)
- Stress: high (2)
- Complexity: highly complex (5)
- Experience/Training: nominal (1)
- Procedures: not avai lable (50)
- Ergonomics/FFD/Work Processes: Nominal (1)
Total: .5 (I think it could be higher, like .7, but SPAR-H goes over 1 then. I think complexity should have more of an affect, and procedures should have less of an impact. If there were less than an hour available, I would estimate a 1.0.)
Relevant Action Performance Shaping Factors
- Time: nominal (1)
- Stress: nominal (1)
- Complexity: nominal (1)
- Experience/Training: nominal (1)
- Procedures: nominal (1)
- Ergonomics/FFD/Work Processes: Nominal (1)
Total: .001 (the action part of this HEP is simple and does not require a procedure)
HEP Calculation Diagnosis: .5 Action: .001 Final HEP (Independent) 5.E-01 Final HEP (Low Dependence) 5.E-01 Final HEP (Moderate 6 .E-01 Dependence)
Final HEP (High Dependence) 8.E-01
Final HEP (Complete 1
Dependence)
/Vlict,,.e{/e l<.ict,,.firte Division of Risk Assessment Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission 301-415-3153 From: Mitman, Jeffrey Sent: Monday, October 22, 2018 11:54 AM To: Montecalvo, Michael <Michael.Montecalvo@nrc.gov>; Kiclh line, Michelle
<Michelle.Kichline@nrc.gov>; Leech, Matthew <Matthew.Leech@nrc.gov>; Demers, Jerrod
<Jerrod.Demers@nrc.gov>; Hartle, Brandon <Brandon.Hartle@nrc.gov>
Cc: Fong, CJ <CJ.Fong@nrc.gov>
Subject:
Re-evaluation of HFE for EOG non recovery - Clinton Mike Franovich has requested that I poll the branch for their insights and input into a significant HFE on the Clinton SOP. The SOP address a 3.5 day period during their most recent refueling outage during which neither the Div. 1 nor 2 EOG was available. The SERP has determined that the finding is preliminarily White. A choice letter has been written and the licensee has requested a Reg. Cont.
The HFE looks at the non-recovery probability of the inadvertently unavailable EDG2. It is a dominant HFE and is driving the results.
The purpose of the re-evaluation is to use it as additional sensitivity analysis and input into the final decision making.
Attached is the HFE analysis itself minus the quantification. I have not supplied the quantification as I don't want it to influence your analysis. Also attached are the annunciator response card for the associated annunciators. Finally, attached are the relevant procedures.
Hopefully, the HFE analysis document will supply all of the information needed to understand the scenario and what the operators would have faced. In reality, you will probably have questions.
Please review the HFE document. Also the procedures to the degree you feel necessary. I'll try to find a time slot after the SRA counterparts meeting this week to meet as a group to answer any questions and to go through the quantification.
There is one additional piece of information that I want everyone to have. The non-recovery probability for an EOG based on data is 0.88 for the one hour available.
Thanks for the help.
Jeff Mitman
All but t he first attachment is non-responsive due to narrowing the request to exclude licensee orginated documents. Documents excluded is are: 5285_R27c Alarm Panel 5285 Annunciators; 3506.0 1_R38 EDG and Support Systems; CPS 4200.01 Loss of AC Power; and CPS 3501 .01 High Voltage Auxiliary Power System .
From: Mitman, Jeffrey Sent: Mon, 22 Oct 2018 15:54:13 +0000 To: Montecalvo, Michael;Kichline, Michelle;Leech, Matthew;Demers, Jerrod; Hartle, Brandon Cc: Fong, CJ
Subject:
Re-evaluation of HFE for EDG non recovery - Clinton Attachments: HFE Task Analysis - SD- EPS-XHE-XM-NRl0H (EDG2) Re-evaluation.doc, 5285_ R27c ALARM PANEL 5285 ANNUNCIATORS AT 1PL12JB.pdf, 3506.0l_R38 EDG and Support Systems.pdf, 4200.01, Loss of AC Power.pdf, CPS 3501.01 High Voltage Auxiliary Power System.pdf Mike Franovich has requested that I poll the branch for their insights and input into a significant HFE on the Clinton SOP. The SOP address a 3.5 day period during their most recent refueling outage during which neither the Div. 1 nor 2 EDG was available. The SERP has determined that the finding is preliminarily White. A choice letter has been written and the licensee has requested a Reg . Cont.
The HFE looks at the non-recovery probability of the inadvertently unavailable EOG2. It is a dominant HFE and is driving the results.
The purpose of the re-evaluation is to use it as additional sensitivity analysis and input into the final decision making.
Attached is the HFE analysis itself minus the quantification. I have not supplied the quantification as I don't want it to influence your analysis. Also attached are the annunciator response card for the associated annunciators. Finally, attached are the relevant procedures.
Hopefully, the HFE analysis document will supply all of the information needed to understand the scenario and what the operators would have faced. In reality, you will probably have questions.
Please review the HFE document. Also the procedures to the degree you feel necessary. I'll try to find a time slot after the SRA counterparts meeting this week to meet as a group to answer any questions and to go through the quantification.
There is one additional piece of information that I want everyone to have. The non-recovery probability for an EDG based on data is 0.88 for the one hour available.
Thanks for the help.
Jeff Mitman
Human Failure Event (HFE) ID: SD-EPS-XHE-XM-NR01 H (b)(5) 03/05/2020
(b)(5) 2 03/05/2020
(b)(5) 4 03/05/2020
(b )(5) 5 03/05/2020
(b)(5) 6 03/05/2020
(b )(5) 7 03/05/2020
(b)(5) 8 03/05/2020
{b )(5) 9 03/05/2020
From: Kichline, Michelle Sent: Mon, 29 Oct 2018 18:25:56 +0000 To: Mitman, Jeffrey
Subject:
Re-evaluation of my Re-evaluation of HFE for EOG non recovery - Clinton My previous evaluation assumed that the only way to find the problem was for someone to walk in the room and notice the valves were out of place because it seemed likely to me that DC load shedding would occur quickly , before troubleshooting could occur or the lineup procedures could be referenced. Based on our discussion, I have re-evaluated the diagnosis portion of the HEP assuming that there is a full hour available to perform the action before any load shedding or ELAP declaration occurs. Therefore, licensee staff willl have time to go through the EOG operating procedure to get to the step that will instruct them to close the valves. I also used your excel spreadsheet, which appears to be calculating the adjusted HEP correctly. My spreadsheet was not. That makes the diagnosis HEP .168 when adjusted for the 3 negative PSFs. There are no changes to the action part of the evaluation.
Relevant Diagnostic Performance Shaping Factors
- Time: Nominal (1)
- Stress: high (2)
- Complexity: moderately complex (2)
- Experience/Training: nominal (1)
- Procedures: available but poor (5)
- Ergonomics/FFD/Work Processes: Nominal (1)
Total: .2 without adjustment, .168 with adjustment for negative PSFs.
Relevant Action Performance Shaping Factors
- Time: nominal (1)
- Stress: nominal (1)
- Complexity: nominal (1)
- Experience/Training: nominal (1)
- Procedures: nominal (1)
- Ergonomics/FFD/Work Processes: Nominal (1)
Total: .001 (the action part of this HEP is simple and does not require a procedure)
From: Kichline, Michelle Sent: Thursday, October 25, 2018 2:40 PM To: Mitman, Jeffrey <Jeffrey.Mitman@nrc.gov>
Subject:
RE: Re-evaluation of HFE for EDG non recovery - Clinton Relevant Diagnostic Performance Shaping Factors (PSF)
- Time: Extra time (.1)
- Stress: high (2)
- Complexity: highly complex (5)
- Experience/Training: nominal (1)
- Procedures: not available (50)
- Ergonomics/FFD/Work Processes: Nominal (1)
Total: .5 without adjustment, .336 w ith adjustment for 3 negative PSFs (I think it could be higher, like .7, but SPAR-H goes over 1 then. I think complexity should have more of an affect, and procedures should have less of an impact. If there were less than an hour available, I would estimate a 1.0.)
Relevant Action Performance Shaping Factors
- Time: nominal (1)
- Stress: nominal (1)
- Complexity: nominal (1)
- Experience/Training: nominal (1)
- Procedures: nominal (1)
- Ergonomics/FFD/Work Processes: Nominal (1)
Total: .001 (the action part of this HEP is simple and does not require a procedure)
HEP Calculation Diagnosis: .5 Action: .001 Final HEP (Independent) 5.E-01 Final HEP (Low Dependence) 5.E-01 Final HEP (Moderate 6.E-01 Dependence)
Flnal HEP (High Dependence) 8.E-01 Final HEP (Complete 1
Dependence)
Mict-.e{(e Kict-./ine Division of Risk Assessment Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission 301-415-3153 From: Mitman, Jeffrey Sent: Monday, October 22, 2018 11:54 AM To: Montecalvo, M ichael <Michael.Montecalvo@nrc.gov>; Kiclhline, Michelle
<Michelle.Kichline@nrc.gov>; Leech, Matthew <Matthew.Leech@nrc.gov>; Demers, Jerrod
<Jerrod.Demers@nrc.gov>; Hartle, Brandon <Brandon.Hartle@nrc.gov>
Cc: Fong, CJ <CJ.Fong@nrc.gov>
Subject:
Re-evaluation of HFE for EDG non recovery - Clinton Mike Franovich has requested that I poll the branch for their insights and input into a significant HFE on the Clinton SOP. The SOP address a 3.5 day pe riod during their most recent refueling outage during w hich neither the Div. 1 nor 2 EOG was available. The SERP has determined that the finding is preliminarily White. A choice letter has been written and the licensee has requested a Reg. Conf.
The HFE looks at the non-recovery probability of the inadvertently unavailable EDG2 . It is a dominant HFE and is driving the results.
The purpose of the re-evaluation is to use it as additional sensitivity analysis and input into the final decision making.
Attached is the HFE analysis itself minus the quantification . I have not supplied the quantification as I don't want it to influence your analysis. Also attached are the annunciator response card for the associated annunciators. Finally, attached are the relevant procedures.
Hopefully, the HFE analysis document will supply all of the information needed to understand the scenario and what the operators would have faced . In reality, you will probably have questions.
Please review the HFE document. Also the procedures to the degree you feel necessary. I'll try to find a time slot after the SRA counterparts meeting this week to meet as a group to answer any questions and to go through the quantification.
There is one additional piece of information that I want everyone to have. The non-recovery probability for an EDG based on data is 0.88 for the one hour available .
Thanks for the help.
Jeff Mitman
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Rajapakse Champa ; Torres Edgardo: Wi lson George : Solornakos Matina Subject : SENSITIVE PRE-DEC ISIONAL INFORMATION: Enforcemen t Highlights Apri l 2, 2019 Date: Tuesday. April 02 , 2019 10:47:34 AM Attachments : Enforl;llilli!nU:!ighlig h ~ o d f Good morning ,
The attached table contains pre-decisional enforcement information. Please do not distribute without prior EICS approval.
Please contact Sarah Bakhsh [630 81 0 4380], Kenneth Lambert [630 81 0 4376], or Paul Pelke [630 81 0 4375] if you have questions.
OFFICIAL USE ONLY PREDEGISIONAL INFORMATION U.S. NUCLEA.11 REGULATORY COMMISSION
- - - WARNING - - -
SENSITIVE ALLEGATION MATERIAL THE ATTACHED DOCUMENT CONTAINS MATERIAL WHICH MAY RELATE TO AN OFFICIAL NRC INQUIRY OR INVESTIGATION WHICH MAY BE EXEMPT FROM PUBLIC DISCLOSURE PURSUANT TO ONE OR MORE PARTS OF TITLE 10, CODE OF FEDERAL REGULATIONS.
OFFICIAL USE ONLY SPECIAL HANDLING REQUI RED WHEN NO LONGl!R NEEDED, DISPOSE OP THE ATTACHED DOCUMENT IN A SENSITIVE UNCLASSIFIED WASTE RECEPTACLE OR BY DESTROYING BY ANY MEANS THAT CAN PREVENT RECONSTRUCTION IN WHOLE OR IN PART. SEE MANAGEMENT DIRECTIVE 12.& FOR INSTRUCTIONS ON DELETING SENSITIVE ALLEGATION MATERIAL FROM ELECTRONIC STORAGE MEDIA.
ACCESS TO INFORMATION CONTAINED HEREIN IS LIMITED TO STAFF AS REQUIRED fOR BRIEFING AND RESOLUTION. DISCLOSURE Of INFORMATION TO UNAUTHORIZED PERSONS IS PROHIBITED.
NIIC FOIUII 752 (ZOOSI
OFFICIAL USE ONLY PREDECISIONAL INFORMATION Allegation and Enforcement Status April 2, 2019
OFFICIAL I !SE ONbY PREDECISIONAL INFORMATION Sensitive Information Internal Use On ly w
02-Apr-2019 REGION 3 ENFORCEMENT STATUS REPORT RIii PANEL None RIii RNDRA PRE-BRIEFS None CONFERENCES None ALTERNATIVE DISPUTE None RESOLUTION MEETINGS OTHER NOTABLE None MEETINGS A red check mark (v ) in this report indicates a pending enforcement action is approaching or has exceeded a goal. Below are the timeliness goals associated with various types of enforcement actions.
Type of case Timeliness goal Clock starts Average case processing time shall be S180 days.
No case shall exceed 330 days.
01 report Issuance to Enforcement Panel: 45 days Based on 0 1report Enforcement Panel to Choice Letter Issuance: 30 days Date of 0 1report Choice Letter to PEC/ADR: 45 days (written 30 days)
PEC/ADR/Written Response to Final Action: 30 days Standard Cases Average processing time shall be S120 days.
Exit Date (Non-0I), (Non-SOP) No case shall exceed 160 days.
All enforcement actions issued s 90 days. [NRR]
Average processing time shall be s120 days. [OE]
(Non-0I) Exit Date (OE)
No case shall exceed 160 days.[OE]
Letter acknowledging receipt due to licensee within 30 days, if more than Receipt of licensee's Disputed violations 30 days are necessary to review and respond. Final response to licensee letter shall be issued in S90 days, unless OE agrees to an extension.
OFFICIAL USE ONLY PREDEGISlmJAL INFORMATION REGION Ill ENFORCEMENT
SUMMARY
A ril 2, 2019 DIVISION/ EA# LICENSEE ISSUE NEXT ACTION ADMIN DAYS DNMS EA-18-157 Gerdau - Monroe Mill DNMS EA-18-172 USS Silversides Submarine Museum DNMS EA-19-007 Zevacor Molecular DNMS EA-19-011 Air Zoo DNMS EA-19-015 IRISNDT DNMS EA-19-019 Wayne State University DNMS EA-19-020 Jan X-Ray Services DNMS EA-19-026 Army
OFFICIAL USE mJLY PREDECISIONAL INFORMATION REGION Ill ENFORCEMENT
SUMMARY
A ril 2, 2019 DIVISION/ EA # LICENSEE ISSUE NEXT ACTION ADMIN DAYS DRP EA-18-104 Clinton Failure to follow several Completed 4/1/19 procedures resulted in 2 90 (NRR) 221 EDGs unavailable at the 11 /21/18 same time. 120 (OE) 189 1/22/19 EA-15-206 Monticello (b)(5), (b)(?)(A)
OFFICIAL USE ONLY - PREDECISIONAL l~ffORMATION
- 1. MATERIALS CASES DIVISION OF NUCLEAR MATERIALS SAFETY LICENSEE EA#, IA # ,
OE GOAL ISSUE RECENT & PENDING ACTIONS NRC CONTACTS 0 1#
DNM S Gerdau - Monroe EA-1 8-157 120 days: Mill (b)(5), (b)(?)(A) 05104/19 DNMS: Craffey EICS: Lambert OE: Sreenivas OGG:
Admin:
USS Silversides EA-1 8-172 Submarine Museum DNMS: Lin EICS: Lambert OE: Holiday OGC:
Admin:
DNMS Zevacor Molecular EA-19-007 90 days: DNMS: Draper 04/10119 EICS: Lambert OE: Marenchin OGC:
Admin:
Ind. Reviewers:
Steve Bell/ Geoff Edwards DNMS Air Zoo EA-19-01 1 DNMS: Learn/Lin EICS: Lambert OE: Marenchin OGC:
Admin:
DNMS IRISNDT EA-19-015 01 180 days: DNMS:
Null/Piskura 06118/19 EICS: Lambert OE: Furst OGC:
Admin:
OFFICIAL USE ONLY PREDEGISIONAL l~ffORMATlmJ DIVISION OF NUCLEAR MATERIALS SAFETY LICENSEE EA#, IA#,
OE GOAL ISSUE RECENT & PENDING ACTIONS NRC CONTACTS 01#
DNMS Wayne State Univ. EA-19-019 (b)(5), (b)(7)(A)
DNMS : Craffey EICS: Lambert OE: Marenchin OGC:
Admin: Clay DNMS Jan X-Ray Serv . EA-19-020 120 days: DNMS : Craffey xx/xx/18 EICS: Lambert OE: Marenchin OGC:
Admin: Clay DNMS Army EA-19-026 DNMS: Nieves EICS: Lambert OE: Marenchin OGC:
Admin: Clay
OFFICIAL USE ONLY PREDECISIONAL INFORMATION
- 2. REACTOR CASES (DRP)
DIVISION OF REACTOR PROJECTS LICENSEE OE & NRR EA#, 01 #,
NRG ISSUE RECENT & PENDING ACTIONS GOALS IA#
CONTACTS OE 120 days Clinton EA-18-104 Failure to follow several 05/17/18 Event date; PD determination date 01/22/19 DRP: Phillips procedures resulted in 2 07/19/18 IFRB held DRS: EDGs unavailable at the 07/26/18 Planning SERP held (sched. for 7/26)
SRA: Kozak same time . xx/xx/418 Complete detailed risk evaluation NRR 90 days EICS: Lambert 09/20/18 SERP held (tent. sched. for 9/20) 11/21/18 OE: Marshfield 09/24/18 Exit with licensee Admin: Clay 10/10/18 draft preliminary white letter to OE and NRR 10/15/18 OE (10/12) and NRR (10/15) review/concurrence received NRR clock is 09/26/18 Strategy form signed limiting 10/15/18 Inspection report/choice letter issued 10/19/18 Licensee written response re reg conference 11/13/18 Meeting notice issued 11/20/18 Pre-conference strategy session 11/30/18 Reg Conference held 12/14/18 Licensee provides additional written response (due 12/15) 02/14/19 Hold post-conference caucus (Final SERP) (2/14) 02/28/19 Hold follow-up post conference caucus (2/28) 03/14/19 DRP provide technical input for final action 03/19/19 EICS provide final action to Admin 03/20/19 Admin place final action into concurrence 03/21/19 Draft action forwarded to OE and NRR 03/26/19 OE and NRR review/concurrence received 03/26/19 EN issued 04/01/19 Final action issued ACTION : Completed 4/1/19
OFFICIAL USE ONLY PREDECISIONAI INFORMATION
- 3. REACTOR CASES (DRS)
DIVISION OF REACTOR SAFETY LICENSEE OE & NRR NRG EA#, 01 # ISSUE RECENT & PENDING ACTI ONS GOALS CONTACTS OE 90 days Monticello EA-15-206 (b)(5), (b)(?)(A)
DRS : D. Hill s EICS: Lambert OE : Marshfield
- 4. ORDERS & CONFIRMATORY ACTION LETTERS ORDERS Division EA#, IA# Licensee Order Description Open or Notes Completed DNMS EA-14-193 Monticello (b)(5), (b)(7)(A)
DNMS EA-16-282 Tilden Mining DRP EA-15-039 Palisades DRS EA-16-022 Davis-Besse
ORDERS Division EA#-, IA#- Licensee Order Description Open or Notes Completed Individual IA-18-043 Mistras Individual IA-16-049 JANX Order dated June 1, 2017 Individual IA-16-059 American Order dated Engineering February 2, Testing 2017 Individual IA-14-039 Cardiology 11 ,
Order dated P.C.
August 4, 2015 Individual IA-09-035 Philadelphia Veterans Affairs Medical Center Individual IA-10-010 Philadelphia Veterans Affairs Medical Center Individual IA-13-012 University Nuclear and Diagnostics, LLC Individual IA-13-024 Dresden (b)(5), (b )(7)(A)
ORDERS Division EA#, IA# Licensee Order Description Open or Notes Completed Individual IA-1 3-025 Dresden (b)(5), (b)(7)(A)
Note to requester: A draft version of EA-18-1 04 is withheld in its entirety under FOIA exemption B5 (deliberative process priviledge).
(b)(5)
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Note to requester: This document is publicly available at https://www.nrc.gov/docs/ ML 1305/ ML13050A934.pdf. The yellow highlighted portions are only in the responsive version provided here.
NRC INSPECTION MANUAL APHB MANUAL CHAPTER 0609 APPENDIX G, ATTACHMENT 1 SHUTDOWN OPERATIONS SIGNIFICANCE DETERMINATION PROCESS PHASE 1 INITIAL SCREENING AND CHARACTERIZATION OF FINDINGS 1.0 APPLICABILITY This attachment and its exhibits are designed to provide U.S. Nuclear Regulatory Commission (NRG) inspectors and management with a framework for use in the initial screening and characterization of potentially risk-significant Shutdown (SD) issues within the Initiating Events, Mitigation Systems, and Barrier Integrity cornerstones for the Significance Determination Process (SDP). In addition, this process identifies findings of very low risk significance that do not warrant further NRG engagement. This appendix is intended to be used when the plant is shutdown with at least one fuel bundle in the reactor and temperature and pressure are within the normal Residual Heat Removal (RHR)/ Decay Heat Removal (DHR) conditions , otherwise return to IMC 0609, Attachment 4, "Initial Characterization of Findings."
2.0 ENTRY CONDITIONS Before entering an issue into the SDP, the inspector will screen the issue to determine its documentation threshold as described in IMC 0612, Appendix B, "Issue Screening. If .an inspector screens a finding in accordance with Appendix Band is directed by Appendix B to determine its risk significance, and if that finding involves shutdown operations with fuel in the reactor, then the inspector will initially screen that finding using the SD Phase 1 screening questions found in Exhibits 2-5.
3.0 PHASE 1 SDP OVERVIEW Appendix G of the SDP is a tool which uses a quantitative risk method to characterize the risk of events or conditions during SD. All issues, including those at SD, that screen more than minor in Appendix B of IMC 0612 are then characterized using IMC 0609, Attachment 4. If the finding impacts the Initiating Events , Mitigation Systems, or Barrier Integrity Cornerstone, then Table 3 in IMC 0609, Attachment 4 will refer the inspector to the appropriate SDP Appendix. In the case of a SD finding, it will refer them to this appendix. The inspector would utilize the information from their initial characterization of the finding in IMC 0609, Attachment 4, Tables 1 & 2, but would transfer to this Appendix in Step A of Table 3 when directed by IMC 0609, Attachment 4.
The purpose of the screening questions in Exhibits 2-5 is to determine if the issue can be characterized as Green before entering into a more detailled analysis with IMC 0609, Appendix G Phase 2 or 3.
Issued Date: 05/09/14 0609 Appendix G, Att.1
Phase 1 is intended to be accomplished by the inspection staff, with the assistance of a Senior Reactor Analyst (SRA), if needed. Inspectors should collect information needed for determining the significance of the finding, such as the structure, system, or component affected, the nature of the degradation, and the duration of the degraded condition . Inspectors should obtain licensee risk perspectives as early in the SOP process as a licensee is prepared to offer them, and use the SOP framework to the extent possible to evaluate the adequacy of the licensee's input and assumptions.
END Exhibit 1 - User Guidance for Appendix G Phase 1: Initial Screening and Characterization of Findings Exhibit 2 - Initiating Events Screening Questions Exhibit 3- Mtigating Systems Screening Questions Exhibit 4 - Barrier Integrity Screening Questions Exhibit 5 - External Events Screening Questions Issued Date: 05/09/14 2 0609 Appendix G, Att.1
Exhibit 1 - User Guidance for Appendix G Phase 1: Initial Screening and Characterization of Findings Step 1: Perform an initial screening of the inspection finding.
CAUTION: Most shutdown finding risk results are driven by the operator failure probabilities. When evaluating shutdown findings it is important to be aware of any conditions or events that may impact operator response.
1.1 It is important to note that current fleet Pressurized Water Reactor (PW R) designs do not have automatic safety actuation systems during shutdown. Also, in the current Boiling Water Reactor (BWR) designs there is no requirement to have the automatic low level injection initiation functional in cold shutdown and refueling. Therefore, the risk significance of many findings will rely on operator's ability to diagnose the problem and perform appropriate actions. Successful operator actions are dependent on plant procedures, available time, complexity of the mitigation response, training, ability to diagnose the problem, etc.
Therefore, when evaluating the initial screening of a shutdown finding it is important to be aware of any conditions or events that may impact the operators' ability to diagnose and respond to a shutdown initiator. If you have any questions or are uncertain about an issue you are evaluating contact your Regional SRA.
1.2 Table G1 provides an overview of key safety functions and systems important to safety during shutdown, the inspector should use this table while completing the appropriate Exhibit 2-5. This table attempts to collect all potential influences on both the human actions and equipment that can affect the risk at shutdown.
Inspectors should use the information in Table G1 to determine which, if any, categories of Exhibits 2-5 that are influenced by specific findings .
1.3 If the finding affects the safety of a reactor at shutdown, THEN IDENTIFY the affected cornerstone( s):
D Initiating Event Mtigation Systems Reactor Coolant System (RCS) Barrier D Fuel Barrier D Containment Barriers NOTE: When assessing the significance of a finding affecting multiple cornerstones, the finding should be assigned to the cornerstone that best reflects the dominant risk of the finding.
CONTINUE to the appropriate Exhibit 2-5 to answer the screening questions.
1.4 Use the decision logic in the exhibits when answering the screening questions to determine if the issue can be characterized as Green. Note that the examples Issue Date: 05/09/14 Ex 1-1 0609 Appendix G, Att. 1
provided in the exhibits are not all inclusive. tt you have any questions or are uncertain about an issue you are evaluating contact your Regional SRA.
Step 2: tt the finding screens as Green, then document in accordance with IMC 0612.
Step 3: tt the finding screens as other than Green, perform an Appendix G Phase 2 or Phase 3 analysis as directed by the screening questions in Exhibits 2-5 Table G1 Generic SD Key Safety Functions and System Dependencies 1 Safety Function Major Systems Supporting Systems Initiating Event Scenarios Decay Heat
- Residual Heat *AC Power
- Loss of RHR (LORHR)
Removal Removal
- DC Power
- Loss of SDC (LOSDC)
- Decay Heat
- RHR/ DHR Heat
- Loss of Off-site Power Removal Exchanger (LOOP)
- Shutdown
- Component Cooling
- Loss of Inventory (LO I)
Cooling Water (PWR)
- Steam 2
- Power Operated
(PWR)
- Instrumentation (i.e.,
- Loss of Component
(Low Pressure Heat Exchanger (PWR)
Injection, High inlet/outlet
- Loss of Residual Heat Pressure Temperature and Removal Service Water Injection, RHR/ DHR Flow (RHRSW) (BW R)
Charging System Indication, Core Exit (PWR) Thermocouples
- Control Rod Drive (PW Rs with reactor System (BWR) head installed only)
- Core
- Residual Heat Spray(BWR) Removal Service Water (BWR)
- Training
- Procedures
- Time to Boil and Time to Core Uncovery 1 This table is not intended to be all-inclusive. It is intended to give the inspector an overview of important systems and key safety functions to consider when characterizing the SD finding.
Issue Date: 05/09/14 Ex 1-2 0609 Appendix G, Att. 1
1 T able G1 Ge ne ric SD Ke ySafety Functions and Syste m Dependencies Safety Function Major Systems Supporting Systems Initiating Event Scenarios Inventory Control
- Low Pressure
- Drain Down Isolation
- Loss of Inventory (LOI Injection Valve(s)
- High Pressure
- AC Power
- Loss of Level Control2 Injection
- Charging System
- Control Rod Drive
- Instrumentation (i.e.,
RCS Level, RHR/DHR Heat Exchanger inlet/outlet Temperature and RHR/ DHR Flow Indication, Core Exit Thermocouples (PW Rs with reactor head installed only)
- Training
- Procedures
- Time to Boil and Time to Core Uncovery Electric Power
- Emergency
- All Initiators Availability Diesel Generators
- Batteries and Battery
- Offsite Power Charges Feeds
- rvlotor Generators
- Offsite
- Inverters Transformers
- Training
- Offsite Inverters
- Procedures
- Time to Boil and Time to Core Uncovery 2 Loss of level control requires a Phase 2 or Phase 3 if Loss of Level for PW Rs: inadvertent loss of 2 feet of RCS inventory when not in mid-loop OR inadvertent entry into reduc ed inventory OR mid-loop conditions OR inadvertent loss of 2 inches of RCS inventory when in mid-loop conditions.
Loss of Level for BWRs: inadvertent loss of 2 feet of RCS inventory OR inadvertent RCS pressurization.
Issue Date: 05/09/14 Ex 1-3 0609 Appendix G, Att1
1 Table G1 Generic SD KeySafety Functions and System Dependencies Safety Function Major Systems Supporting Systems Initiating Event Scenarios Reactivity Control
- AC Power
- Reactivity (inadvertent
- Control rod and
- DC Power criticality) associated drive
- Nuclear mechanisms Instrumentation
- Chemical and
- Training Volume Control
- Procedures System (PWR)
- Time to Boil and Time
- Standby Liquid to Core Uncovery Control (BWR)
Containment
- Hydrogen Control *AC Power
- All Initiators
- Containment
- DC Power Closure
- Motive Power to close Capability Hatches (assuming
- Penetrations loss of AC power)
- Temporary c las ures/penetrations
- Training
- Procedures
- Time to Boil and Time to Core Uncovery Issue Date: 05/09/14 Ex 1-4 0609 Appendix G, Att1
Exhibit 2 - Initiating Events Screening Questions A. SD Initiators
- 1. Does the finding increase the likelihood of a SD initiating event?
o If YES., Stop. Go to Appendix G Phase 2.
If NO, continue.
B. Loss of Coolant Accident - Loss of Inventory (LOI) Initiators
- 2. Did a LOI event result in a leakage such that if the leakage were undetected and/or unmitigated in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or less it would cause the currently operating decay heat removal method to fail (e.g., level would drop to below the hotleg suction of the operating decay heat removal pump (PWR), orto the shutdown cooling isolation Level 3 setpoint (BWR})?
o If YES., Stop. Go to Appendix G Phase 2.
o If NO, continue.
- 3. Is the LOI event self-limiting such that leakage will stop before impacting the operating method of decay heat removal?
o If YES, continue.
If NO ., Stop. Go to Appendix G Phase 2.
C. Transient Initiators
- 4. LOOP - Did the initiator occur when refuel canal/cavity was flooded?
If YES, continue.
o If NO ., Stop. Go to Appendix G Phase 2.
- 5. LOOP - Did the initiator occur when the time to boil off RCS inventory to the top of active fuel (TAF) was shorter than the time to recover offsite power?
o If YES., Stop. Go to Appendix G Phase 2.
o If NO, continue.
Issue Date: 05/09/14 Ex 2-1 0609 Appendix G, Att1
If YES, continue.
If NO - Stop. Go to Appendix G Phase 2.
- 7. Loss of Level Control (LOLC) or Over Drain (OD) - For PW Rs, did the initiator occur when reactor level was in reduced inventory?
If YES+- Stop. Go to Appendix G Phase 2.
If NO, continue.
D. External Event Initiators
- 8. Does the finding increase the likelihood of a fire or internal/external flood that could cause an SD initiating event?
If YES +- Stop. Go to Phase 3.
If NO, screen as Green.
Issue Date: 05/09/14 Ex 2-2 0609 Appendix G, Att1
Exhibit 3 - Mitigating Systems Screening Que stions A. Mitigating Structure System Component (SSC) and Functionality
- 1. If the finding is a deficiency affecting the design or qualification of a mitigating SSC, does the SSC maintain its operability or functionality?
o If YES, screen as Green.
tt NO, continue.
- 2. Does the finding represent a loss of system safety function?
If YES + Stop. Go to Appendix G Phase 2.
If NO, continue.
- 3. Does the finding represent an actual loss of safety function of at least a single Train for greater than its Tech Spec Allowed Outage Time, OR two separate safety systems out-of-servIce for greater than its Tech Spec Allowed Outage Time?
If YES + Stop. Go to Appendix G Phase 2.
tt NO, continue.
4.a) tt the cavity is flooded, does the finding represent an actual loss of safety function of one or more non-Tech Spec Trains of equipment during SD designated as risk-significant (e.g. 10CFR50.65), for greater than 24 hrs?
If YES
- Stop. Go to Appendix G Phase 2.
If NO, continue.
4.b) tt the cavity is not flooded, does the finding represent an actual loss of safety function of one or more non-Tech Spec Trains of equipment during SD designated as risk-s ignificant (e.g. 10CFRS0.65), for greater than 4 hrs?
If YES + Stop. Go to Appendix G Phase 2.
o If NO, continue.
5.a) For PW Rs, does the finding degrade RCS level indication and/or core exit thermal couples (CETs) when the cavity is not flooded?
o If YES + Stop. Go to Appendix G Phase 2.
If NO, continue.
Issue Date: 05/09/14 Ex 3-1 0609 Appendix G, Att1
5.b) For BWRs, does the finding degrade a functional auto-isolation, regardless of whether it is required to be operable or not, of RHR on low reactor vessel level?
o If YES +-- Stop. Go to Appendix G Phase 2.
o If NO, continue.
B. External Event Mtigation Systems (Seismic/Fire/Flood/Severe Weather Protection Degraded)
- 6. Does the finding screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event, using the criteria in Exhibit 5?
o If YES +-- Stop. Go to Phase 3.
o If NO, continue.
C. Fire Brigade
- 7. Does the finding involve Fire Brigade training and qualification requirements , or brigade staffing?
o If YES+-- check if one or more of the following apply:
- The fire brigade demonstrated the ability to meet the required times for fire extinguishment for the fire drill scenarios, and the finding did not significantly affect the ability of the fire brigades to respond to a fire.
- The overall time duration (exposure time) that the Fire Brigade was understaffed was short(< 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />).
o If none of the above apply +-- Stop. Go to IMC 0609, Appendix M.
o If at least one of*the above is applicable, continue.
o If NO, continue.
Issue Date: 05/09/14 Ex 3-2 0609 Appendix G, Att1
- 8. Does the finding involve the response time of the Fire Brigade to a fire?
If YES+- check if one or more of the following apply:
- The fire brigade's response time was mitigated by other defense-in-depth elements, such as area combustible loading limits were not exceeded, installed fire detection systems were functional, and alternate means of safe shutdown were not impacted.
- The finding involved risk-significant fire areas that had automatic suppression systems.
- The licensee had adequate fire protection compensatory actions in place.
If none of the above apply +- Stop. Go to IMC 0609, Appendix M.
If at least one of the above is applicable, continue.
~ NO, continue.
- 9. Does the finding involve fire extinguishers, fire hoses, or fire hose stations?
If YES +- check if one or more of the following apply:
- There was no degraded fire barrier and the fire scenario did not require the use of water to extinguis.h the fire.
- The missing fire extinguisher or fire hose was missing for a short time and other extinguishers or hose stations were in the vicinity.
If none of the above apply +- Stop. Go to IMC 0609, Appendix M.
If at least one of the above is applicable, screen as Green.
If NO, screen as Green.
Issue Date: 05/09/14 Ex 3-3 0609 Appendix G, Att1
Exhibit 4 - Barrier Integrity Screening Questions A. RCS or Fuel Barrier Note: If the finding involves fuel bundle misplacement or misorientation in the reactor core, screen as Green.
- 1. Low Temperature Over Pressurization (LTOP)- For PWRs, does the finding involve an inadvertent Safety Injection Actuation, the unavailability of a PO RV or LTOP relief valve or their associated setpoints during LTOP operations or when it is required?
If YES +- Stop. Go to Phase 3.
tt NO, continue.
- 2. Freeze Seal - Does the finding increase the potential for failure of the freeze seal or if unmitigated have the potential to cause a disruption in RHR/DHR or a LOI event?
If YES +- Stop. Go to Phase 3.
If NO, continue.
- 3. Steam Generator (SG) Nozzles Dams - Does the finding involve improper SG nozzle dam installation (e.g. hot leg manway must be opened first, hotleg SG nozzle dam installed last),
inadequate SG nozzle dam RCS vent path, deficiencies of the SG nozzle dams (Ref GL 88-17 and IN 88-36) or SG nozzle dam functionality?
If YES - Stop. Go to Phase 3.
tt NO, continue.
4.a) Criticality - For PW Rs, does the finding involve the potential for, or an actual, RCS boron dilution event?
If YES +- Stop. Go to IMC 0609, Appendix M .
tt NO, continue.
4.b) Criticality - For BWRs, does the finding involve 2 or more adjacent control rods with the potential to, or actually, add positive reactivity?
If YES +- Stop. Go to IMC 0609, Appendix M .
If NO, continue.
Issue Date: 05/09/14 Ex 4-1 0609 Appendix G, Att1
- 5. Drain Down Path or Leakage Path - Does the finding degrade the ability to isolate a drain down or leakage path?
If YES + Stop. Go to Phase 3.
o If NO, continue.
B. Containment Barrier
- 6. Does the finding degrade the ability to close or isolate the containment (this includes but is not limited to equipment and personnel hatches and permanent and temporary penetrations)?
If YES+ Stop. Go to IMC 0609, Appendix H.
If NO, continue.
- 7. Does the finding degrade the physical integrity of reactor containment (valves, penetrations, containment isolation components)?
If YES + Stop. Go to IMC 0609, Appendix H.
If NO, continue.
- 8. Does the finding involve an actual reduction in function of hydrogen control for BWR Mark Ill and PWR ice condenser containments?
If YES + Stop. Go to IMC 0609, Appendix H.
If NO, screen as Green.
Issue Date: 05/09/14 Ex 4-2 0609 Appendix G, Att1
Exhibit 5 - External Events Screening Questions
- 1. If the equipment or safety function is assumed to be completely failed or unavailable, are ANY of the following three statements TRUE? The loss of this equipment or function by itself, during the external initiating event it was intended to mitigate:
- would cause any of the Initiating Events used by Table G1 for the plant in question;
- would degrade two or more trains of a multi-train safety system or function, or would degrade the only available train, which would defeat the entire safety function;
- would degrade one or more trains of a system that supports a safety system or function.
o If YES ,.. the finding is potentially risk significant due to external initiating event core damage sequences return to screening questions in Exhibits 2-5.
o If NO, continue.
- 2. Does the finding involve the total loss of any safety function, identified by the licensee through a Probalistic Risk Assessment, Individual Plant Examination External Events, or similar analysis, that contributes to external event initiated core damage accident sequences (i.e., initiated by a seismic, flooding, or severe weather event)?
o If YES -the finding is potentially risk significant due to external initiating event core damage sequences return to screening questions in Exhibits 2-5.
o If NO, screen as Green.
Issue Date: 05/09/14 Ex 5-1 0609 Appendix G, Att1
Attachment 1 Revis ion History Page Commitment Accession Description of Change Description Comment Tracking Number Training Feedback Number Issue Date Required Resolution Change And Completion Accession Notice Date Number NIA 05/25/04 Initial issuance NIA NIA CN 04-015 ML13050A934 IMC 0609 App G, Att. 1 is revised to enhance the NIA ML13162A640 05/09/14 usability of this appendix, based on feedback received CN 14-011 from the SRA The formatting was updated to be 0609G-1323 consistent with IMC 0609 Appendix A The checklists ML14120A177 from the previous revision, for PW Rs and BWRs, were combined into one list in the various Exhibits in the 0609G1-1911 attachment using screening questions and decision logic. ML1412A166 The content was updated and reworked to be more user-friendly for inspectors to screen findings to determine if they are Green or a more detailed analysis is needed.
Incorporated feedback from ROPFF 0609G1 -1911 and 0609G-1323. This is a complete reissue no red line.
Issue Date: 05/09/14 Att 1-1 0609 Appendix G, Att1
Human Failure Event (HFE) ID: SD-EPS-XHE-XM-NR01H (b)(5) 05/01/2019
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