ML030870344
| ML030870344 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 02/06/2003 |
| From: | Kreil J Nuclear Management Co |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| FOIA/PA-2003-0094 | |
| Download: ML030870344 (204) | |
Text
kagc I ol -4 Nuclear Management Company STATE CHANGE HISTORY initiate1 AR Screening Que 12/19/2001 9 36 04 PM Owner SCOTT PFAFF by JULIE KREIL V.
SECTION 1 Activity Request Id: CAP001415 CAP Submit Date: 11/29/2001 1:00.00 AM Activity Type:
"<One Line
Description:
Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW in the PRA, a
" Detailed
Description:
While performing an update to the Auxiliary Feed Water (AFW) System model identified in AOP 5B with regards to the availability of the procedural shortcoming was documented in CR minimum recirculation valve with the loss of instrument air. This issue was of this issue 01-2278 with a recommendation to upgrade the procedure. Upon further review this issue has that with PRA engineers, Operations, and Design Engineering, it was discovered lost pnmarily by two further reaching affects as documented below.\\lnstrument air (IA) can be of off-site power where the IA and failure mechanisms. The first, and most likely, is a loss are stripped from the bus and not automatically re-loaded. The Service Air (SA) compressors equipment the instrument air system due to second less likely scenario is a random loss of flow recirculation failure without potential for short term recovery. When IA is lost, the minimum the AFW pumps will start injecting into valves for AFW fail closed.\\During these two transients, Early in the EOPs, the operator is directed to control flow to the steam the steam generators. both steam This may include shutting off flow to one or generators to maintain desired level.
if level is above the desired band If flow from any auxiliary feed pump is reduced generators functional too low (as would occur if the auxiliary feed regulating valves are closed) without mode of recirculation valves, the pump will fail in a very short period of time. This common level) of instrument air and common response to high steam generator failure (common loss has estimated the nsk associated could result in simultaneous failure of all AFW pumps.\\PRA and loss of with this issue. The total risk increase due to both the loss of off-site power of 4 times higher than our assumed base instrument air contribution is approximately a factor overall increase in the area of 2E-4 CDF per year (base risk is around 5E-5 CDF risk with an Current design of plant - deficiency not per year).\\WHY DID EVENT/ISSUE OCCUR?
recognized.\\SIGNIFICANCE/REOUIREMENT NOT MET: See description.
previously Potential common failure mode for all auxiliary feed pumps under certain initiating action is being events.\\CORRECTIVE ACTIONS TAKEN: Operations has been notified and provide temporary instruction for the operation of the AFW taken to brief operation crews and evaluate and discharge valves.\VRECOMMENDATIONS: 1) Engineering needs to further guidance for determine long term corrective action.\\2) PRA needs to evaluate and provide short term Maintenance Rule risk monitonng until new model is implemented.
MASTERLARK, JAMES Initiator Department: EPN Engineering Nuclear Programs Safety Analysis PB Initiator:
12/19/2001 9.36:04 PM Date/Time of Occurrence:
Date/Time of Discovery: 12/19/2001 9:36.04 PM (None)
System:
Identified By: (None)
(None)
(None) Equipment Type (1st):
Equipment # (1st): (None)
(None) Equipment Type (2nd):
Equipment # (2nd): (None)
(None) Equipment Type (3rd):
Equipment # (3rd):
Site/Unit: Point Beach - Common Why did this occur?:
Immediate Action Taken:
Recommendations:
N Q SRO Review Required?: N 0 Notify Me During Eval?:
9/18/2002 https://nmc.ttrackonline.com/tmtrack/tmtrack.dll ?IssuePage&Tableld= 1000&Recordld=55(...
Nuclear Management Company Page 2 of 4 SECTION 2 Operability Status: (None) D Compensatory Actions: N Basis for Operability:
0 External Notification: Y 0 Unplanned TSAC Entry: N SECTION 3 A
Screened?: Y 0 Significance Level:
N INPO OE Reqd?: N Potential MRFF?:
N 0 QA/Nuclear Oversight?: N 0 Licensing Review?:
Good Catch/Well Doc'd?: NA SECTION 4 Inappropriate Action:
Process: (None) Activity: (None)
(None) Human Perf Fail Mode: (None)
Human Error Type:
(None) Process Fail Mode: (None)
Equip Failure Mode:
Org/Mgt Failure Mode: (None) 0 Group Causing Prob: (None)
Hot Buttons: (None)
SECTION 5 SCOTT PFAFF fg1 Prescreener: (None)
CAP Admin:
Q Project: Corrective Action Process (CAP) ::
0 State: AR Screening Que 0 Active/Inactive: Active Q Owner: SCOTT PFAFF "0Submitter: JULIE KREIL 1!
"* Last Modified Date: 9/12/2002 9.44:02 AM AR Type: Parent
" Last State Change Date: 12/19/2001 9.36:04 PM "0Last Modifier: RICHARD FLESSNER
" Last State Changer: JULIE KREIL 19 0 Close Date:
NUTRK ID: CR 01-3595
- of Children: 4
References:
CR 01-2278 RCE 01-069 GOOD CATCH Update: L\\(20011204 PB2171 JMK1) Operability Determination (OD) Part I, Revision 0, of CR 01-3595 was approved on 11/30/01. Operable But Degraded - or Operable But Nonconforming - meets the minimum required level of performances, compensatory measures ARE required
\\Operability Determination (OD) Part I, Revision 1 of CR 01-3595 was approved on 12/01/01.
Operable But Degraded - or Operable But Nonconforming - meets the minimum required level of performances, compensatory measures ARE required.
Operability Determination (OD) Part 1, Revision 2 of CR 01-3595 was approved by a DSS on 04/27/02 at 2030. Operable - fully meets performance requirements. No further action https:/Hnmc.ttrackonline.com/tmtrack/tmtrack.dll?IssuePage&Tableld= I 00&Recordld=55(... 9/18/2002
Page 3 of 4 Nuclear Management Company required A copy of the approved version is attached below.
Prescreen Comments: Operability Status: Operable \Operability Basis: AFFW system has passed all required testing and is operable. An OD has been requested by plant staff. \\SCREENER COMMENTS: Temp info tags will be placed at appropriate locations on the control boards to address this problem This is only a short term fix. \Notification to NRC made at 1705 CST.
Import Memo Field:
OPR Completed?: N OLDACTIONNUM:
subtsid: 0 original-project-id: 32 original-issueid: 001415 Site: Point Beach Cartridge and Frame:
ATTACHMENTS AND PARENT/CHILD LINKS SLinked To Child 'ACE000314' Z Linked To Child 'CA002592' SLinked To Child 'CA002593 E Linked To Child 'CA002594' 0 Linked To OTH003541 S*,,. CA003691: Probabilistic Risk Assessment PRA For Auxila FrL.eedwater System AFW 0, CA003692: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW CA003693" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
/ ~* CA003694: Probabilistic Risk Assessment PRA For Auxilia*y Feedwater System AFW SCA003695" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
/ *,E CA003696° Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW S*L! CA003697: Probabilistic Risk Assessment PRA For Auxiliay Feedwater.System AFW Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW O-CA003698:
,4 **-CA003699 Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
.' CA003699. Probabilistic Risk Assessment PPRA For Auxilia~Ey Fewater System AFW
- CA003700.. P robabilistic Risk Assessm ent RA Fr Au~xi!la--Fed-wt-rSyse-mA SCA003701:
Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW 9/18/2002 https://nmc.ttrackonline.comltmtrack/tmtrack.dll ?IssuePage&Tableld=lOOO&Recordld=55(...
Nuclear Management Company Page 4 of 4
, CA003702 Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW CA003703 Probabilistic_Risk AssessmentePRA For Auxiliay FeedweaterSystem AFW E: CA003704 Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW CA003705" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW Q
Linked To CA003982 Linked To CA003983 I CA004279: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW t * : Linked To CA004388 S& Linked To OTH004389 OD Part 1 rev 2 for CR 01-35 appropved pd_.f (1984402 bytes)
Linked To OTH00451 0 SPrincipal to CA026222: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW Prinicjpalto CA026223. Probabilstic RisSsessment PRA For Auxiliary FeedWater System AFW Principal to CA026224" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
' * *Principal to CA026225: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
/ *"* P~n~ncip~al toQTH026285: Probabilstic RiskAsspessment PRA For Auxilair Feewater System AFW https**lnmc.ttrackonline.com/tmtrackltmtrack.dlI?IssuePage&TabeId= 1000&Recordld=55(... 9/18/2002
Nuclear Management Company Page 1 of 7 STATE CHANGE HISTORY Conduct Work Review Approval &
Conduct Assign Work Assign Work Complete Initiate Work Return 1/712002 1/1812002 2/512002 12/2012001 5.06 01 PM 12.54.54 PM 4 15"10 PM 9.57.31 PM Owner Owner Owner Owner by RICHARD LARRY by LARRY RICHARD by RICHARD LARRY by JAMES RICHARD PETERSON FLESSNER PETERSON FLESSNER PETERSON FLESSNER MASTERLARK FLESSNER
-<1 Complete Update Quality and Close Quality Assign Work Done Approved Return 2/1412002 Check Check 2/19,/2002 2/19/2002 2/6/2002 2:32 56 PM 2 53-33 PM Owner 11:05 11 AM 1.23 07 PM by Owner JULIE by Owner (None)
Owner JULIE by JULIE LARRY MARYBETH MARYBETH by LARRY KREIL KREIL KREIL PETERSON ARNOLD SARNOLD PETERSON Complete Conduct Work Review & Approved Quality and Close Update Approval Check Done Work Complete 5/15/2002 4/27/2002 5/1412002 5/1412002 3 39.50 PM 4.57.47 PM 1.11:53 PM 12:13.36 PM Owner by Owner (None)
Owner by RICHARD Owner PBNP by MARYBETH by RICHARD LARRY FLESSNER CAP Admin MARYBETH RICHARD ARNOLD ARNOLD FLESSNER FLESSNER PETERSON -"
SECTION 1 Activity Request Id: ACE000314 Apparent Cause Submit Date: 12/4/2001 1:00:00 AM Activity Type:
Evaluation Site/Unit: Point Beach Common in Activity Requested: ROOT CAUSE EVALUATION: Perform a Root Cause Evaluation for this issue Evaluation guideline (OEG 001). CARB review of this accordance with the Root Cause to the Root Cause Evaluation is required. \\DESCRIPTION: \While performing an update (AFW) System model in the PRA, a procedural shortcoming was Auxiliary Feed Water valve identified in AOP 5B with regards to the availability of the minimum recirculation with a with the loss of instrument air. This issue was documented in CR 01 -2278 with PRA recommendation to upgrade the procedure. Upon further review of this issue has Operations, and Design Engineering, it was discovered that this issue engineers, below.\\lnstrument air (IA) can be lost primarily further reaching affects as documented where by two failure mechanisms. The first, and most likely, is a loss of off-site power the IA and Service Air (SA) compressors are stripped from the bus and not the automatically re-loaded. The second less likely scenario is a random loss of system due to equipment failure without potential for short term recovery.
instrument air these When IA is lost, the minimum flow recirculation valves for AFW fail closed.\\Dunng the AFW pumps will start injecting into the steam generators Early in the two transients, EOPs, the operator is directed to control flow to the steam generators to maintain if level desired level. This may include shutting off flow to one or both steam generators flow from any auxiliary feed pump is reduced too low (as is above the desired band. If would occur if the auxiliary feed regulating valves are closed) without functional mode recirculation valves, the pump will fail in a very short period of time. This common generator of failure (common loss of instrument air and common response to high steam the risk level) could result in simultaneous failure of all AFW pumps.\\PRA has estimated power associated with this issue The total risk increase due to both the loss of off-site than and loss of instrument air contribution is approximately a factor of 4 times higher year (base our assumed base risk with an overall increase in the area of 2E-4 CDF per design risk is around 5E-5 CDF per year).\\WHY DID EVENT/ISSUE OCCUR? Current
- 1) Engineering of plant - deficiency not previously recognized.\\FECOMMENDATIONS:
needs to needs to further evaluate and determine long term corrective action.\\2) PRA short term Maintenance Rule risk monitoring until new evaluate and provide guidance for model is implemented.
eOO&Recordld=85... 9/18/2002 A
Nuclear Management Company Page 2 of 7 0 CATPR: N Initiator: PETERSON, LARRY Initiator Department: EX Engineering Responsible Group Code: (None)
Processes PB Responsible Department: Engineering Activity Supervisor: LARRY PETERSON Activity Performer: RICHARD FLESSNER nI SECTION 2 Priority: 2 Due Date: 5/27/2002 Mode Change Restraint: (None) Management Exception From PI?: N 0 OA/Nuclear Oversight?: N O Licensing Review?: N NRC Commitment?: - N 0 NRC Commitment Date:
SECTION 3 Apparent Cause Evaluation: (Note: This RCE required revision because additional information and insight were developed during preparations for the NRC regulatory conference held on this issue.)
Purpose:
The purpose of this investigation is to determine the root and contributing causes of why the emergency operating procedural inadequacies existed that contributed to the increased core damage frequency (CDF) for the Auxiliary Feedwater System during a loss of instrument air event, and why these inadequacies where not identified previously.
Event Synopsis:
During a review of the AFW PRA model in June 2001, it was discovered that the AFW recirculation valves were not modeled. Subsequent discussions disclosed that under a loss of instrument air condition (IA), operators might close the AFW discharge valves to stop AFW flow. Because the recirculation valves fail close on loss of IA, these actions could deadhead the AFW pumps and result in pump damage. Initially the procedural concern was directed at AOP-5B, but it was later realized that the AOP was not the only concem. Operator actions could be taken earlier in an accident scenario to control or stop AFW flow, as directed by steps in EOP-0.1, prior to taking manual actions directed by AOP-5B. PRA modeling of the AFW system continued and on 11/26/01 a factor of 2.3 risk increase in CDF was identified. As discussions with site personnel continued, additional initiating events were identified and on 11/28/01 a revised PRA model was run that changed the risk estimate to a factor of 4 to 5 increase in CDF. Condition report CR 01-3595 was initiated at 1445 on 11/29/01 and an NRC event notification was made at 1705 the same day.
Conclusions:
The investigation found that the EOP validation process is the barrier that failed, causing the weakness in EOP-0.1. The EOP validation process failed because it did not evaluate the interaction among design, procedures, and human error timeline analysis.
It was only from this integrated perspective that a loss of instrument air causing the recirculation valves to fail closed, combined with a possibility that an operator could close the discharge valve on an AFW pump, and the timing of this action prior to implementation of the abnormal procedure for loss of instrument air (AOP-5B) could the potential be seen to damage multiple AFW pumps. The combination of FMEA, timeline studies, and human error analysis is a recently implemented practice in the industry unique to PRA. Without the use of these combined analyses, it was not reasonable that previous evaluations would have identified this vulnerability.
https://nmc.ttrackonline.comntmtrack/tmtrack.dll?IssuePage&TableId=1 000&Recordld=85!... 9/18/2002
Pagze 3 of 7 Nuclear Management Company Nuclear Safety Significance:
Preliminary PRA results show that the vulnerability described in this report, prior to the procedural changes, was potentially risk significant. Although the initiating event frequencies are low to moderate, when an unrecoverable IA scenario is considered risk becomes significant due to the consequences of a total loss of all AFW pumps requiring feed and bleed without the pressunzer PORVs. The nsk results are highly dependant upon human interactions. PBNP operators are trained on AFW system operations and have expenence with degraded IAscenarios. Because of this training and experience, it is reasonable to assume that operators would have successfully handled this combination of conditions in the unlikely event that it would have occurred.
Root Cause:
The root cause of the EOP procedural weaknesses was the failure of the original EOP validation process barrier to identify that specific operator directions were needed to ensure the operator would properly control or stop AFW flow under a loss of instrument air condition. This barrier failed because the analytical tools needed to identify this vulnerability did not exist at that time. This resulted in a misalignment between plant design and procedural guidance.
Significant contributing causes to this condition continuing to exist were:
-The original PRA model fault trees evaluated system performance primanly on functions described in design documents and only considered operator actions taken to mitigate a failure
-Previous evaluations focused on delivery of the minimum required AFW flow for providing decay heat removal Corrective Action Synopsis:
.EOP-0, EOP 0.1 and ECA-0.0 revised to address AFW control under loss of IA
-Back-up pneumatic supply added to AFW recirculation valves
.AOP-5B revised to incorporate back-up pneumatic supply for recirculation valves
-EOP validation process revised to include PRA
-Simulator enhanced to model potential for AFW pump failure on loss of IA
-Evaluated EOP steps to ensure successful implementation on loss of IA
-Completed detailed evaluation of PRA model for the four top risk-significant systems
-Validated PRA assumptions on next two risk-significant systems (these six systems comprise 80% of CDF risk)
-Continuing detailed evaluations of PRA model for other risk-significant systems
-Enhancing CDF risk reduction by incorporating PRA human error reduction methods into operator training and operating procedures Activity Completed: 1/18/2002 12:52PM - LARRY PETERSON:
Due date extended as requested and approved by F. Cayia in prior update. Retruned to R. flessner for completion.
1118/2002 12:54PM - LARRY PETERSON:
Reassigned to R. Flessner for completion following extension.
2/512002 4:15PM - RICHARD FLESSNER:
RCE report completed on 2/5/02 and forwarded to UP for approval. Actions items generated and report attached.
2/6/2002 1:23PM - LARRY PETERSON:
RCE reviewed and approved. Routed for CA Mgr and CARB approval.
2/1412002 2:32PM - JULIE KREIL:
RCE copy not received by CAP Manager as of 2/14/2002, per RCE Coordinator 2/19/2002 11:05AM - MARYBETH ARNOLD:
RCE electronic copy had been attached to this record; however, it is believed that Windows 2000 migration may have caused a problem with the opening of this document. Document unable to be opened. Assessment group is contacting the RCE evaluator for an additional electronic copy. Hard copy is presently in the hands of the CAP manager awaiting other groups reviews/comments prior to his approval signature.
2/19/2002 2.53PM - MARYBETH ARNOLD:
9/18/2002 https:H/nmc.ttrackon] ine.com/tmtrack/tmtrack.di ]?IssuePage&TableId= OOO&Recordld=85...
Nuclear Management Company Page 4 of 7 A copy of the electronic RCE is attached below. Actions were created by the evaluator as followon to this RCE. See CA003691 through CA003705 for these items.
OTH003541 tracks the presentation and acceptance by CARB. This item is considered CLOSED.
4/27/2002 12:13PM - MARYBETH ARNOLD:
This item is being re-opened per the request of the Activity Performer and Plant Management. A revision to the Root Cause Evaluation is being prepared.
5114/2002 3:39:50 PM - RICHARD FLESSNER:
The revised report was approved on 5/14102 by the Engineering Director and sent to the CAP Manager.
5/14/2002 4:57.47 PM - RICHARD FLESSNER Larry Peterson and Lori Armstrong approved Rev. 1 of the RCE on 5114/02. Approval to close granted by Larry Peterson. RCE forwarded to CAP Manager for final approval.
5/15/2002 1:11:53 PM - MARYBETH ARNOLD.
RCE 01-069, Revision 1 was approved by CAP on 05/15/02. Actions were created from the Revision 0 RCE.
5/15/2002 1:13:07 PM - MARYBETH ARNOLD:
OTH003541 tracks the presentation of Revision 1 to the CARB. CLOSED.
6/14/2002 8:08:57 AM - JULIE KREIL:
At 6/04/2002 CARB meeting, CARB accepted Revision 1 of this RCE with no further actions or editorial changes to be made (reference NPM 2002-0292).
SECTION 4 (None) Licensing Supervisor: (None)
QA Supervisor:
0 ACE Extent of Condition Grade: 0 "OACE Event Descdiption Grade: 0 0 ACE CATPR Grade: 0 "0ACE Corrective Actions Grade: 0 0 ACE Apparent Cause Grade: 0 SECTION 5
- Project: Apparent Cause Evaluation (ACE) 0 State: Done 0 Active/Inactive: Inactive AR Type: Daughter 0 Owner: (None)
Assigned Date:
1/18/2002 0 Submitter: JAMES MASTERLARK RICHARD "0Last Modified Date: 9/312002 7:12:54 PM Q Last Modifier:
FLESSNER fg)
MARYBETH
" Last State Change Date: 5115/2002 1:11:53 PM 0 Last State Changer:
ARNOLD (
0 Close Date: 5/15/2002 1:11:53 PM 0 One Line
Description:
Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW NUTRK ID: CR 01 -3595 Child Number: 1
References:
CR 01-2278 RCE 01-069 GOOD CATCH https://nmc.ttrackonline.com/tmtrack/tmtrack.dil ?IssuePage&Tableld= 1000&Recordld=85!... 9/18/2002 X
Nuclear Management Company Page 5 of 7 NPM 2002-0292 Update: (12/05/01 LJP) Received Action into Group. SEP\Responsible Person. RAF:RICHARD FLESSNER Due Date: 01/03/2002\\(20011205 XX4869 LJP) Set Work Priority to
- 2. Assigned priority 2 based on level B CR requiring RCE.\\(12112/01 RAF) Changed the Due Date from: 01/0312002 to 01/10/2002\The due date for this RCE was established in the Charter by the Plant Manager as 1/10/2002 based on the normal 30 day period plus an additional week to account for the holiday season. Approval of the Charter by Fred Cayia on 12/4/2001 satisfies the requirement for a SVP Direct Report approval of a due date different from the NP. A copy of the Charter has been forwarded to the PLA for documentation. (12/05101 LJP) RECEIVED ACTION INTO GROUP.
SEP\RESPONSIBLE PERSON: RAF:RICHARD FLESSNER DUE DATE:
01/03/2002\\(20011205 XX4869 LJP) SET WORK PRIORITY TO 2. ASSIGNED PRIORITY 2 BASED ON LEVEL B CR REQUIRING RCE.\\(12/12/01 RAF) CHANGED THE DUE DATE FROM. 01/03/2002 TO 01/10/2002\THE DUE DATE FOR THIS RCE WAS ESTABLISHED IN THE CHARTER BY THE PLANT MANAGER AS 1/10/2002 BASED ON THE NORMAL 30 DAY PERIOD PLUS AN ADDITIONAL WEEK TO ACCOUNT FOR THE HOLIDAY SEASON. APPROVAL OF THE CHARTER BY FRED CAYIA ON 12/4/2001 SATISFIES THE REQUIREMENT FOR A SVP DIRECT REPORT APPROVAL OF A DUE DATE DIFFERENT FROM THE NP. A COPY OF THE CHARTER HAS BEEN FORWARDED TO THE PLA FOR DOCUMENTATION.
4/27/2002: This RCE required revision because of additional information and insight developed during prepartions for the NRC regulaory conference held on this issue.
Action item OTH004389 was created to track completion of the revised RCE.
Import Memo Field: An extension request was granted by Fred Cayia on 1/24/02 to a revised due date of 2/7/02. A draft report was provided to key personnel on 1/22/02. Comments received from Operations/Training on 1/23 and L. Peterson on 1/24 require additional time for resolution.
A new due date of 5/27/2002 has been set based on 30 days from the date it was reopened, to revise the RCE. (RAF)
CAP Admin: PBNP CAP Admin Site: Point Beach OLD_ACTIONNUM:
Cartridge and Frame:
NOTES/COMMENTS S4' Note created during 'Return' transition by RICHARD FLESSNER (1/7/2002 5:06:01 PM) following e A due date extension to 1/24/02 has been approved verbally by Fred Cayia and Rick Mende in response to the mail (dated 1/7/02):
Fred, of The Root Cause Team met for several hours today to review progress on the RCE report. We were at the stage pnmarily due to reviewing event and causal factor information for events in the 1979 to 1990 time frame. The events were several areas need modifications and responses to industry operating experience (NRC and INPO). It became evident that involved were. These areas are FSAR content over time, additional research in order to understand what the causal factors IST program changes, IPE program development, training program influences, and DBD changes.
2 factors influencing I have concluded that the committed date for the RCE completion of 1/10/02 cannot be met. There are season would have on the Team's momentum, and 2) the new this conclusion: 1) 1 underestimated the impact the holiday areas of research identified in today's meeting will take additional time to develop and evaluate.
information for 1990 The remaining scope of work consists of evaluating these new areas of research, developing E&CF factors, determination of root and contributing causes, and development and 2001, identification of appropriate causal The Team wants to do a negotiation of corrective actions. The Team feels that this work can be accomplished by 1/24/02.
interested thorough job on this RCE because of its safety significance and the level of scrutiny that it will receive by the discussed this parties. I am therefore requesting a 2 week extension of the committed due date to 1/24/02. I have extension with Rick Mende and have his concurrence.
Respectfully, 9/18/2002 https:/Hnmc.ttrackonline.com/tmtrack/tmtrack.dll?IssuePage&TableId= 1000&Recordld=85....
Nuclear Management Company Page 6 of 7 Rich Flessner Team Leader Note created during 'Return' transition by JULIE KREIL (2/14/2002 2 32:56 PM)
Copy of RCE not received by CAP Manager as of 2/1412002, per RCE Coordinator.
ATTACHMENTS AND PARENT/CHILD LINKS Linked From Parent 'CAP001415' OTH003541: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
, CA003691: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
&i CA003692: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW CA003693" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW F CA003694" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
& CA003695" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW Fý E! CA003696" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW O'g-CA003697: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
@1 CA003698" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW CA003699. Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
.0' .*CA003700"Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
'- & CA003701: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW CA003702: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW CA003703 Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
£3. CA003704" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW E:! CA003705" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW Z:! CA004388 Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW Z!2 OTH004389: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
. RCE 01-069 Rev 1 (419840 bytes) https://nmc.ttrackonline.com/tmtrack/tmtrack.dll?IssuePage&Tableld=1000&Recordld=85!... 9/18/2002
Nuclear Management Company Page 7 of 7 S 0 J Linked from CA026222 Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW Linked_from_CA026223 Probabilistic Risk Assessment PRA For Auxiliary FeedwateLSyvstem AFW Linked from CA026224: Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW Linked from CA026225" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW 9/18/2002 https://nmc.ttrackonline.comltmtrackltmtrack.dll?IssuePage&Tableld= 1000&Recordld=85¶...
9j7:7 INTERNAL Corn nmed £oMudearExi, CORRESPONDENCE e~c.
NPM 2002-0252 To: M. E. Warner From: D. A. Hettick Date: May 15, 2002
Subject:
ROOT CAUSE EVALUATION 01-069, Revision 1 Copy To: S. J. Nikolai D. D. Schoon A. J. Cayia T. Coutu - KNPP J. Purcell - KNPP S. J. Thomas L. J. Armsfrong V. A. Kaminskas J. R. Anderson G. A: Corell T. Taylor D. Weaver R. Repshas - KNPP T. Sullivan (P458) J. J. Walsh K. Peveler R. Nicolai - KNPP B. Day M. McCarthy S F. Putman - KNPP R. Milner M. B. Arnold T. L. Zifko R. Wood L. Peterson C. Krause J. P. Schroeder T. Staskal R. Flessner L. A. Schofield/JOS T. Y Fessler/OSRC File Attached is Root Cause Evaluation (RCE)01-069, Revision 1, for your review. This RCE is an evaluation of Increased CDF in AFW PRA Model Due to Procedural Inadequacies Related to Loss of Instrument Air. The corrective actions associated with this RCE will be tracked under CR 01-3595.
If you have any questions or would like to discuss the report, please call me at Extension 6498.
Approved: I-- .,,,
- D.Ik.ettick tlz Attachment
commit'i'o°u r --- " Point Beach Nuclear Plant Increased CDF in AFW PRA Model Due to Procedural Inadequacies Related to Loss of Instrument Air RCE 01-069 Revision 1 (CR 01-3595)
Event Date: November 29, 2001 Report Date: May 14, 2002 Principal Investigators:
R. Flessner - Team Leader C. Krause J. P. Schroeder T. Staskal R. Wood Approved By:
Group Lead #6 Peterson Dt Issue Manaer - Lori Armstrong 6AP Manager - Denlsnki*ettick " Date
IncreasedCDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I I InadequaciesRelated to Loss of Instrument Air Table of Contents Executive Summary ............................................................................. 3 I.
II. Event Narrative ..................................................................................... 5 Extent of Condition Assessment ..................................................... 9 III.
Nuclear Safety Significance .......................................................... 10 IV.
Report to External Agencies ......................................................... 11 V.
Data Analysis ................................................................................. 12 VI.
12 Information & Fact Sources .................................................................
32 Evaluation Methodology & Analysis Techniques ................................
32 Data Analysis Summary ......................................................................
35 Failure Mode Identification .................................................................
36 VII. Root Causes & Contributing Factors .............................................
Corrective Actions ...................................................................... 37 VIII.
40 IX. References ......................................................................................
41 X. Attachments ..................................................................................
Team Charter ............................................................... 42 Attachment A:
Event Timeline ............................................................ 43 Attachment B:
Why Staircase ............................................................ 49 Attachment C:
Event & Causal Factor Chart ...................................... 51 Attachment D:
2 1%
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. 1 I InadequaciesRelated to Loss of Instrument Air I. Executive Summary (Note: This RCE required revision because additional information and insight were developed during preparations for the NRC regulatory conference held on this issue.)
Purpose:
The purpose of this investigation is to determine the root and contributing causes of why the emergency operating procedural inadequacies existed that contributed to the increased core damage frequency (CDF) for the Auxiliary Feedwater System during a loss of instrument air event, and why these inadequacies where not identified previously.
Event Synopsis:
During a review of the AFW PRA model in June 2001, it was discovered that the AFW recirculation valves were not modeled. Subsequent discussions disclosed that under a loss of instrument air condition (IA), operators might close the AFW discharge valves to stop AFW flow. Because the recirculation valves fail close on loss of IA, these actions could deadhead the AFW pumps and result in pump damage. Initially the procedural concern was directed at AOP-5B, but it was later realized that the AOP was not the only concern. Operator actions could be taken earlier in an accident scenario to control or stop AFW flow, as directed by steps in EOP-0.1, prior to taking manual actions directed by AOP-5B. PRA modeling of the AFW system continued and on 11/26/01 a factor of 2.3 risk increase in CDF was identified. As discussions with site personnel continued, additional initiating events were identified and on 11/28/01 a revised PRA model was run that changed the risk estimate to a factor of 4 to 5 increase in CDF. Condition report CR 01-3595 was initiated at 1445 on 11/29/01 and an NRC event notification was made at 1705 the same day.
Conclusions:
The investigation found that the EOP validation process is the barrier that failed, causing the weakness in EOP-0.1. The EOP validation process failed because it did not evaluate the interaction among design, procedures, and human error timeline analysis. It was only from this integrated perspective that a loss of instrument air causing the recirculation valves to fail closed, combined with a possibility that an operator could close the discharge valve on an AFW pump, and the timing of this action prior to implementation of the abnormal procedure for loss of instrument air (AOP-5B) could the potential be seen to damage multiple AFW pumps. The combination of FMEA, timeline studies, and PRA.
human error analysis is a recently implemented practice in the industry unique to Without the use of these combined analyses, it was not reasonable that previous evaluations would have identified this vulnerability.
3
IncreasedCDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of InstrunentAir Nuclear Safety Significance:
Preliminary PRA results show that the vulnerability described in this report, prior to the procedural changes, was potentially risk significant. Although the initiating event frequencies are low to moderate, when an unrecoverable IA scenario is considered risk becomes significant due to the consequences of a total loss of all AFW pumps requiring feed and bleed without the pressurizer PORVs. The risk results are highly dependant upon human interactions. PBNP operators are trained on AFW system operations and have experience with degraded IA scenarios. Because of this training and experience, it is reasonable to assume that operators would have successfully handled this combination of conditions in the unlikely event that it would have occurred.
Root Cause:
The root cause of the EOP procedural weaknesses was the failure of the original EOP validation process barrier to identify that specific operator directions were needed to ensure the operator would properly control or stop AFW flow under a loss of instrument air condition. This barrier failed because the analytical tools needed to identify this vulnerability did not exist at that time. This resulted in a misalignment between plant design and procedural guidance.
Significant contributing causes to this condition continuing to exist were:
"* The original PRA model fault trees evaluated system performance primarily on functions described in design documents and only considered operator actions taken to mitigate a failure
"* Previous evaluations focused on delivery of the minimum required AFW flow for providing decay heat removal Corrective Action Synopsis:
"* EOP-0, EOP 0.1 and ECA-0.0 revised to address AFW control under loss of IA
"* Back-up pneumatic supply added to AFW recirculation valves
"* AOP-5B revised to incorporate back-up pneumatic supply for recirculation valves
"* EOP validation process revised to include PRA
"* Simulator enhanced to model potential for AFW pump failure on loss of IA
"* Evaluated EOP steps to ensure successful implementation on loss of 1A
"* Completed detailed evaluation of PRA model for the four top risk-significant systems
"* Validated PRA assumptions on next two risk-significant systems (these six systems comprise 80% of CDF risk)
"* Continuing detailed evaluations of PRA model for other risk-significant systems
"* Enhancing CDF risk reduction by incorporating PRA human error reduction methods into operator training and operating procedures 4
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I [
InadequaciesRelated to Loss of Instrument Air
!!. Event Narrative portion of the PRA In June, 2001 the PRA group was reviewing and revising the AFW flow recirculation valves model. During this review it was discovered that the minimum and effects analysis was were not modeled within the PRA. Therefore, a failure modes was held with past performed to determine potential failure modes. A discussion the AOPs and EOPs. It operations personnel about how the system was operated within air, the operators may use was then determined that upon a complete loss of instrument or the flow control valve.
the EOPs and stop AFW flow by closing the discharge MOV instrument air, the AFW However, since the recirculation valve fails closed on a loss of was discussed with a pump would not have adequate recirculation flow. This issue pumps could be damaged in design engineer who informed the PRA group that the AFW a short period of time without adequate recirculation flow.
personnel who reviewed the This issue was then discussed with Operations Training actions were also EOPs and discussed what operator actions would be. The operator that upon a complete loss confirmed with an Operations crew. The actions assumed were Trip or Safety Injection, and of instrument air, entry would be made into EOP-0, Reactor procedures would ensure that then into EOP-0.1, Reactor Trip Response. Steps in these level is high the operator is at least one AFW pump was available. In EOP-0.1, if S/G discharge valve, the AFW directed to STOP flow. If flow were stopped, by closing the recirculation valve failing pump would fail due to lack of minimum flow caused by the be repeated on additional closed. The potential exists that this same evolution could in a similar configuration, the AFW pumps. Since this is a dual unit event with both units same problem could also happen on the second unit.
a specific note to gag open the It was noted that AOP-5B, Loss of Instrument Air, had into the procedure and timing recirculation valves, but the information was located well discharge valves. PRA showed that it would not be adequate to preclude closing the to be risk significant even personnel understood that this failure mode had the potential PRA model development was not though the actual significance wasnot known since the 7/6/01 to document this problem yet completed. PRA personnel initiated CR 01-2278 on the need to gag the and identify potential corrective actions to place steps addressing It was assumed that the recirculation valves open earlier in the sequence of AOP-5B.
of the action could be AOP was sufficient to address the concern, but the timing improved to ensure that the action would be successful.
Procedure group with a An action item was created on 7/10/01 for the Operations to a more prominent position in the recommendation to move the step (AOP-5B step 24) item priority was set at 4 and procedure and consider using a foldout page. The action held between PRA and the due date was established as 8/21/01. Discussions were group evaluation to determine the Operations personnel and it was expected that a PRA Initial Operations review of significance of the issue would be completed by 8/20/01.
a priority to restore instrument air, AOP-5B indicated that the procedure was laid out in of the risk significance of which is the correct response for that procedure. The evaluation on quantifying the entire PRA the as found configuration of the procedure is dependent 5
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of InstrumentAir model. This was not completed until October, due to the complexity of developing a complete two-unit model. The original model used a single unit and simplified common systems. The PRA group informed Operations on 8/20/01 that the evaluation was not completed as expected and additional time was required to evaluate the actual significance and the type of action that should be done. At that time modifications and procedural changes were being considered.
The PRA group completed some preliminary modeling on 10/19/01 that indicated the potential for a high risk was involved and informed Operations that the AFW pump recirculation valves should be procedurally addressed. Based on further discussion, it was decided that a change to the Alarm Response Procedure for instrument air low header pressure (ARP C01 A 1-9) could address the concern. The PRA group was to submit a procedure feedback form for the desired change. The original action item was closed on 11/14/01 and a new action item was created on 11/14/01 to track the changes to the ARP and assigned to Operations. Operations discussed the request with PRA personnel and gave the new action item a priority of 3 with a due date of 12/26/01, based on expected completion of the PRA model and Safety Monitor update in December.
During that discussion some concerns were raised by Operations about the adeqiuacy of procedural changes to address the issue. Specifically, the concern was that the ARP may not be the most effective way of protecting the AFW pumps during high activity in the Control Room, i.e., the loss of instrument air may not take priority and the ARP may not "bereferred to.
Additional discussions took place between Operations, PRA and a design engineer concerning the appropriate corrective actions and what risk might be involved if the procedural remedy was not completed or was inadequate. On Monday, 11/26/01, the PRA modeling adjustments were completed and a factor of 2.3 risk increase in Core Damage Frequency (CDF) was identified, which is considered high. Additional discussions took place between Engineering and Operations to determine further actions that may be appropriate.
A meeting between Operations and Engineering was held at 1300 on Wednesday, 11/28/01, to discuss significance and actions. During the discussion it was discovered that the loss of instrument air was more than just a random loss, a loss of offsite power (LOOP) or other events could also initiate the event. A re-evaluation of risk including the LOOP event resulted in an estimated factor of risk increase of 4 to 5 in CDF.
Operability was also discussed. It was concluded that there was no operability concern because no equipment degradation, failure, or non-conformance had been identified.
Regardless, the level of concern was great enough that further prompt actions were felt to be justified. The Design Engineering Manager briefed the Operations Manager on the situation later that afternoon. The Operations Manager also updated the Plant Manager on the situation.
On Thursday morning, 11/29/01, the Operations Manager briefed the NRC Resident Inspectors on the issue and informed them that we were evaluating this apparent vulnerability and the risk significance. Operations decided that use of temporary 6
IncreasedCDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air information tags and briefing of all watch standers would be an important step to reduce risk; an evaluation of possible procedure enhancements was also initiated. At 1000, PRA personnel briefed the STA and Shift Manager on the issue and discussed potential wording for temporary placards to be placed on the control panels.
At 1100, PRA personnel discussed potential reportability concerns with Licensing. It was not clear if this issue was reportable because it involved a procedure and was not an equipment issue - additional discussions were needed. At 1130, PRA personnel briefed the NRC Resident Inspector on the issues and answered questions regarding risk impact and human error probabilities. During the afternoon, Licensing and Engineering personnel evaluated the reportability aspect further. It was concluded that the conservative decision would be to report the issue, even though a specific reporting criteria could not be identified. At 1445, PRA personnel initiated Condition Report 01 3595 and brought it to the Work Control Center for SRO screening at 1538. The Operations Manager took part in discussions involving operability and the need for an Operability Determination (OD). Since the issue identified in CR 01-3595 did not affect equipment, the decision was made that an OD was not required; however, the details of those discussions were not captured in either the CR or the screening comments. The SRO screening was completed at 1553 with the event determined to be reportable as a an OD.
procedural inadequacy and not requiring At 1520, the oncoming crew was briefed on the concerns of this potential event and temporary information tags were placed adjacent to the controls for 1/2P-29 and P-38 A/B that provided a reminder of the minimum flow requirements for each AFW pump.
At 1700, the Operations Manager provided the Plant Manager with an update on the issue. At 1705, Event Notification EN 38525 was made to the NRC via the ENS phone.
(See Section V. for details)
On Friday morning, 11/30/01, the Licensing Manager received a phone call from the acting NRC-NRR Project Manager for Point Beach, concerning confusion over the event notification. A return conference call was made with Engineering personnel to address NRR questions. A decision was made to provide a supplemental event notification providing additional details. The Operations Manager had additional conversation with the NRC Resident Inspectors and concluded that to formally document the operability of the AFW system, an OD would be initiated to capture the discussions held during the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Operations requested that Engineering provide an OD and informed the Shift Manager that it was expected to be completed that afternoon. At Noon, the Operations Manager met again with the NRC Resident Inspectors and their supervisor to address NRC concerns regarding AFW operability prior to 11/29/01 and in its current configuration. The Plant Manager and Operations Manager had a conference call with NRC Region III to discuss operability of the AFW system.
At 1400, a simulator scenario was run to obtain information on plant response to a loss of offsite power coincident with a rapid loss of instrument air pressure. Additional scenarios were run on 11/30 and 12/1.
7
IncreasedCDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air At 1645, temporary procedure changes were completed for EOP-0 and EOP-0.I to reflect the guidance provided earlier to operators via the temporary information tags.
At 1700, the Plant Manager was informed that a 5 person NRC incident investigation team would arrive on 12/3/01. At 1746, a supplemental event notification was made to the NRC to clarify the discussion on the potential for an AFW system failure as described in the original event notification (EN 38525).
At 1755, Engineering completed Revision 0 of the OD that concluded that the AFW system was Operable but Non-Conforming. This was based in part on a statement in the FSAR that "each pump has an AOV controlled recirculation line back to the condensate storage tanks to ensure minimum flow to dissipate pump heat." The compensatory actions already in effect were listed in the OD as required actions. The Plant Manager and Operations Manager reviewed the OD content and then briefed the Senior NRC Resident Inspector. The OD was then brought to the Control Room and accepted at 2015. On Friday evening, just-in-time (J1T) training was provided to the swing shift crew on the simulator on this event; JIT was also provided to the mid-shift crew on the simulator prior to assuming the watch.
On Saturday, 12/1/01, at 0720 JIT was provided to the oncoming dayshift crew on the simulator prior to assuming the watch. A staff meeting was held from 0930 to 1200 to prepare for the NRC inspection team. A revised OD was prepared at 1500 to expand the discussion on AFW pump motor duty cycles. The Control Room accepted it at 1515.
On Monday, 12/3/01, CR 01-3595 was screened and assigned to Engineering to perform an apparent cause evaluation. Another meeting was held from 1000 to 1200 in preparation for the NRC inspection team. At that meeting it was decided that a root cause evaluation would be a more appropriate response to this event. The Plant Manager approved the RCE Charter on 12/4/01.
The NRC Inspection Team arrived onsite on 1213/01 and conducted a technical debrief on 12/7/01. A preliminary exit meeting was held on 12/13/01.
An expert on Human Error Probabilities was brought onsite on 12/4/01 to help quantify the risks associated with the procedural weaknesses that were identified. His evaluation estimated that there was about a 50% chance that the operator would shut the discharge valve and fail to recognize that the minimum flow recirculation valve did not open when flow was stopped as S/G levels rose above 65% on the narrow range.
On 12/4/01, CR 01-3633 was initiated by Engineering on the ability of the Motor Driven Auxiliary Feedwater Pumps (MDAFWP) to respond to an Appendix R fire coincident with a loss of offsite power and instrument air because of a lack of documentation related to the potential for closure of the recirculation valves due to loss of instrument air. CR 01-3648 was initiated by Engineering on 12/5/01 on the same issue when four specific fire zones were identified as having the potential to cause an AFW pump auto-start 8
IncreasedCDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. 1 I InadequaciesRelated to Loss of Instrument Air coincident with discharge and recirculation valve closure, resulting in pump damage. An OD was completed for CR 01-3468 on 12/7/01 that concluded the MDAFW Pumps were Operable but Non-Conforming, with the required compensatory measures of performing hourly fire rounds in the specified fire zones. An event notification on this issue was made at 1926 on 12/05/01 (EN #38541)
Permanent revisions to EOP-0 and EOP-0.1 were implemented on 12/14/01. As PRA reviews continued, it was recognized that the closure of the AFW recirc valves could occur after an operator had already taken action to put the pumps in the recirculation mode. Additional changes were made to those procedures and ECA-0.0 on 12/20/01 to address this concern. As additional information becomes available, procedure improvements are often implemented to continually improve their quality.
i11. Extent of Condition Assessment The root cause of this event is attributed to a weakness in the original EOP validation process where the effects of a loss of instrument air were not adequately evaluated. This occurred because the validation process did not evaluate the interaction between design, procedures and human error timeline analysis. It was only from this perspective that a loss of IA causing the recirc valves to fail closed combined with a possibility that an operator could close a discharge valve on an AFW pump and the timing of this action prior to implementation of the abnormal procedure for loss of IA (AOP-5B) could the potential be seen to damage multiple AFW pumps. This validation process was believed to be consistent with industry practices.
Because of this event, the previously held belief that AOP-5B, Loss of Instrument Air, adequately directed the required operator actions was found to be faulty because actions were required while in an EOP, prior to performing AOP subordinate actions. This event identified a specific concern with AFW control, but there may be other operator actions that are unique to a loss of instrument air condition that were not adequately considered in the EOPs. A review of EOP steps was performed to ensure that the stated operator actions could be performed under a loss of instrument air condition.
The original PRA model fault trees evaluated system performance primarily on functions described in design documents and did not adequately consider human actions. The current PRA model review uses a methodology that integrates system performance with potential human actions to obtain a spectrum of plant responses. This more rigorous approach should identify any other assumptions used in risk-significant systems that have not adequately considered human actions and any risk-significant vulnerabilities in the emergency operating procedures. The four highest risk-significant systems have had a detailed review of the PRA model completed already. The assumptions for operator actions for the next two highest risk-significant systems have also been validated. These six systems comprise 80% of the CDF risk. The detailed review of the PRA model for the remaining risk-significant systems is continuing.
9
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air The lack of integration of human error reduction methods into operations training and emergency procedure development processes may allow situations to exist where PRA risk reduction has not been optimized. Procedures and training associated with high-risk human error events will be reviewed against human error reduction methods to ensure that reasonable risk reduction has been achieved.
IV. Nuclear Safety Significance Any complete loss of IA for a significant time is expected to result in a reactor trip and an AFW start signal due to a loss of normal feedwater (the normal feed water regulating valves fail closed on loss of air). Under this postulated condition, all components of the AFWS are now and continue to be fully capable of performing their design functions supporting automatic starting and supplying sufficient flow to the steam generators to mitigate any transient or accident by removal of decay heat. It is the continued function of the AFWS, in response to directed operator actions to control AFWS flow, and the lack of specific guidance contained within the EOPs regarding a loss of IA, that is the issue identified in this report.
A PRA assessment of the possible failure modes and effects associated with an IA failure identified a previously unrecognized vulnerability. This failure would have been caused by a combination of a design limitation, a specific sequence of postulated operator actions, and a lack of clear guidance within the EOPs. This combination could result in failure of one or more of the AFW pumps due to aggressive AFW flow reduction (as may be expected in response to a steam generator overfill or RCS over cooling) after automatic system start and flow had been established. The likelihood of success or failure in the postulated scenario is highly dependent upon plant transient response (which may vary with the nature of the initiating event, initial power levels, etc.) and operator response. Operator response is highly dependent upon prior training, procedural usage, system knowledge and awareness, experience, and other human effectiveness (HE) factors. It should be noted that a control board alarm is provided (Instrument Air Header Pressure Low) to alert the operator to the existence of an initiating condition for this event and that established plant procedures direct the restoration of IA (both Emergency Operating Procedures and Abnormal Operating Procedures), and the manual gagging open of the minimum flow recirculation valves in the event that IA cannot be promptly restored (AOP-5B). PBNP has experienced partial losses of IA, including one event involving the loss of all off-site power and another involving a low IA header pressure alarm following a reactor trip. In each of these cases the operators demonstrated the ability to cope with the loss of IA casualty and recover IA header pressure before it had an adverse affect on plant equipment or response.
Preliminary PRA results show that the vulnerability described in this report, prior to the procedural changes, was potentially risk significant. Although the initiating event frequencies are low to moderate, the unrecoverable IA scenario was risk significant due to the consequences of a total loss of all AFW pumps requiring feed and bleed 10
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air without the pressurizer PORVs. The risk results are highly dependant upon human interactions. PBNP operators are trained on AFW system operations and have experience with degraded IA scenarios. Because of this training and experience, it is reasonable to assume that operators would have successfully handled this combination of conditions in the unlikely event that it would have occurred.
Although the AFWS met, and continues to meet, all of its design and licensing requirements, the postulated initiating event of a loss of IA, in conjunction with a misaligned procedure, had the potential to affect redundant trains of the AFWS, a safety related system. Since it could be postulated that the same operator action could have impacted all the AFWS pumps, the result could be the complete loss of the AFWS safety related function. Accordingly, this event has also been identified as a possible safety system functional failure (SSFF).
V. Report to External Agencies Condition Report 01-3595 was initially brought to the PBNP Work Control Center for an SRO screening at 1538 on November 29,2001. During this screening, a determination was made that this event should conservatively be reported to the NRC in accordance with 10 CFR 50.72(b)(3)(v) as a condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to:... (D) Mitigate the consequences of an accident. This is an eight-hour non-emergency notification. During the discussion of reportability it was noted that 10 CFR 50.72 Paragraph (b)(3)(vi) clarifies paragraph (b)(3)(v) by noting that, "Events covered in paragraph (b)(3)(v) of this section may include one or more procedural errors, equipment failures, and/or discovery of design, analysis, fabrication, construction, and/or procedural inadequacies." The last of these items appeared as though it may be applicable in this situation. The following elements also entered into the notification determination:
NUREG-1022 notes that the level of judgment for reporting an event is a reasonable expectation that the event or condition could lead to preventing fulfillment of a safety function. The intent of these criteria is to capture those events regardless of whether there was an actual demand.
- Example (20) in NUREG-1022 Page 64 directs that system interactions that are found as a result of ongoing routine activities may be reportable.
- When in doubt concerning issues of reportability, it is our policy (consistent with the directions in NUREG-1022) to make the report.
The NRC notification was made using the Emergency Notification System (ENS) telephone at 1705 on November 29th. Event number EN 38525 was assigned to this notification.
On the morning of November 30'h, as a courtesy, the PBNP acting Project Manager at NRC-NRR was telephoned to advise him of the event notification. He had several 1I
Increased CDF in AFWPRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air questions that were answered in a follow-up call later in the morning. At 1746 on November 30, 2001, the ENS event notification was supplemented to further clarify the discussion of the specific failures postulated and to reiterate that the potential failure would involve only the AFWS pump recirculation valves.
A Licensee Event Report (LER 266/2001-005-00) was submitted within 60 days of this event as required by 10 CFR 50.73.
Vi. Data Analysis Information & FactSources Document Review Results Modifications
- M-623 / 624 - TDAFP Alternate Bearing Cooling Supply, issued 911179
Description:
In response to an NRC Evaluation of the AFW system, this MR provided a cooling water supply to the TDAFP bearing coolers that is independent of AC power. The supply is taken from the diesel powered Fire Water system.
are Evaluation: The MR enabled the TDAFP to cope with a SBO. Since the TDAFPs the only pumps available for decay heat removal during the first hour of the SBO, operation of the pumps at low flows requiring recirculation flow is not probable. This modification was performed prior to the original EOP-0.1 being issued in 1985.
Therefore, it is not reasonable that this modification would have identified the EOP procedural vulnerability.
IC-274 - Modify Logic To Keep Recirculation Valves Open, issued 2/1180 (Canceled 8/32/82)
Description:
Modify the control scheme of the recirculation valves to keep valves normally open. The reason for this change was to provide a path for the first off check lifting valve leakage back to the CST. This change would prevent the leakage from solving a the pump suction relief. The modification was canceled since it was only intended to symptom of the real problem; check valve leakage. The modification still have the recirculation valves fail to the shut position.
with Evaluation: The modification was attempting to resolve symptoms associated check valve leakage. The modification would not have permitted a continuous recirculation path. This modification was originated and cancelled prior to the that reviews original EOP-0.1 being issued in 1985. Therefore, it is not reasonable associated with this modification would have identified the EOP procedural vulnerability.
12
Increased CDF in AFW PRA Model Due to Procedural RUE UI-O0* Kev. j InadequaciesRelated to Loss of InstrumentAir
- MR 83-104 - AFW System Discharge MOV Controls, issued 8/1/83 automatic
Description:
The MDAFP discharge valves were modified to provide MDAFPs.
actuation of the valves similar to the automatic starting logic for the provided to the Evaluation: The MR was a response to NUREG-0737 to ensure AF is failed on loss of air or S/Gs without operator action. The recirculation valves either in compliance shut as flow to the S/G increased therefore, these valves were already action and the design with the NUREG. This MR deals with eliminating an operator action is taken limitation of the recirculation valves is not introduced until an operator prior to the (i.e. throttling AF discharge flows). This modification was performed it is not original symptom-based EOP-0.1 being issued in 1985. Therefore, reasonable that this MR would identify the EOP procedural vulnerability.
- MR 88-099 - AFW Pump Mini-Recirculation Line Improvements, issued 7/7/88 89-04, the recirculation
Description:
In response to NRC IE Bulletin 88-04 and GL instability.
line flows were increased to prevent pump degradation due to hydraulic increased this to The minimum pump flow pror to this MR was 30 gpm. The MR TDAFPs. The MR minimum flow to 70 gpm for the MDAFPs and 100 gpm for the did not change the operation of the recirculation valves.
needed for adequate Evaluation: PBNP did a design review of the recirc capacity initiated to increase long-term protection of the AFW pumps. This modification was did not alter the the recire flow capacity to the required levels. The modification were reviewed to operating modes of the recire valves. System operating procedures very specific design the extent that this design change impacted them. Therefore, this vulnerability.
change and review would not identify the EOP procedural issued
- MR 92-091/092/093 - IST Testability of AF Recirculation Line AOVs, 6/19192 bypass valves were
Description:
In order to simplify stroke testing of these AOVs, installed around the control solenoid.
need to bypass the Evaluation: The MR was small scope focusing only on the IST Program had solenoid to allow stroke testing of the valve. At this time, the for these valves. The already identified the shut position as the safety related position scope of this MR was not an opportunity to identify the issue.
Nitrogen MR 97-038*A/B - MDAFP Discharge Pressure Control Valve Backup Supply and Cable Separation, issued 4/15/97 AOVs (common electrical
Description:
The MR prevented redundant failures of the MR 97-038*B fault) and pump runout due to loss of IA (Ref. LER 97-014-00).
associated with the discharge provided physical separation for electrical cables associated control pressure control valves (AF-4012 and AF-4019) and their as a backup pneumatic supply.
components. MR 97-038*A installed nitrogen bottles of the functions of the The design description for MR 97-038*B states that one cool the associated pump discharge AOVs is to allow enough flow to the S/Gs to 13
1 I RCEi U-0U t9ev. i Increased CDF in AFW PRA Model Due to Procedural Air InadequaciesRelated to Loss of Instrument required and the associated recirculation during a scenario when pump recirculation is valve fails closed.
pump runout due to a failed open Evaluation: The intent of the MR was to prevent air and low S/G pressures. It discharge AOV as a result of a loss of instrument capability of the discharge pressure appears the focus of the MR was to ensure control the discharge AOVs are needed to control valves. The MR does recognize that valves fail shut. This appears to provide pump cooling flow if the recirculation safety related function and failure of support the idea that the flow to the S/G is the operating procedures were reviewed the recirculation valves is acceptable. System recirc valves were not being modified, for the impact of this design change. Since the with those valves. The failure it was not reasonable to review procedures associated this modification did not on modes and effects analysis of the system performed The ability to throttle the pump consider failures caused by operator actions.
air provides another opportunity (in discharge flow during a loss of instrument action to cause pump damage.
addition to throttling the MOV) for operator Pro~cedures AOP was first issued on 512/86. The AOP-5B, Loss of Instrument Air: This
- manual" step (step 6.0) emphasizing the procedure contained an "immediate action depending on IA header pressure and understanding that AOVs may not function system information. Section R of referred the operator to Appendix A for individual AFW pump recirculation valves as the Appendix A was for Auxiliary Feed, and listed note on manual gag override. The additional failing shut with a corresponding of AFW pumps for sufficient flow to information in that section included monitoring the "minirecirc", and to use the manual gag on prevent overheating due to no maximum recirculation unless continuous feed was "minirecirc" valve to provide content remained essentially the verified through each AFW pump. The procedure which moved time critical actions same until Revision 11 was issued on 9/26/97, the procedure. At that time a specific step from the appendices into the main body of A note was placed before that step (step 21) was added for control of AFW flow.
each AFW pump mini-i'ecirc valve must informing the operator "the manual gag on continuous flow through the pump can be used to provide minimum recirc flow if content is equivalent.
NOT be verified." The current procedure information identifying the correct failure Evaluation: The AOP contained sufficient on loss of LA, the required manual mode of the AFW pump recirculation valves and the need to monitor pump flow. The actions, the concern with pump overheating, to continuously monitor pump flow and content of the note that directed the operator verified, met the requirements of OM 4.3.1 use the manual gag if flow could not be to advise on actions to be taken in the event for note content. OM 4.3.1 allows notes on OM 4.3.1 below).
of changing plant conditions (see discussion Operating Procedures, specifically EOP-0.1, Reactor Trip Response: Emergency 1 be used in the event of concern; EOP-0.
EOP-0. 1, is the PBNP procedure that would 14
RCE 01-069 Rev. 1 IncreasedCDF in AFIV PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air WOG ERG has ever addressed is based on aOWOG ERG. Neither EOP-0. 1 nor the EOP-0.1, in one step (step 3),
the function of the AFW mini recirc flow valves.
bypass valves for feed flow directs the operator to use main feedwater regulator AFW use is directed, and has a control. As a response-not-obtained (RNO) action, valves are not included. A substep to "verify AFW alignment". The mini recirc will trip due to over current NOTE containing the flow rate at which AFW pumps flow control step. In another step induced by pump runout precedes the feedwater level but is not provided details on (step 4), the operator is directed to stabilize S/G is to "stop feed flow to that how to accomplish the task. The RNO action specified is being provided by main feedwater S/G." This action applies whether feed flow pumps. There is also reference to (via the bypass) or by the auxiliary feedwater RCS temperature.
controlling feed flow in step 1 related to maintaining control have basically existed since The steps on S/G level stabilization and feed flow 1985, as a result of NUREG-0737.
the symptom-based EOPs were created in July of instrument air on the mini recirc They have never addressed the impact of loss pump runout) was introduced in valves. The effect of excessive AFW flow (i.e.,
about 1995.
not address loss of instrument air, nor The WOG ERGs for Reactor Trip Response do recirc flow capability. The WOG do they specifically address AFW pump mini to be addressed by the owner. The considers such aspects to be plant specifics, contains little information on what original WOG developmental guidance from 1984 how. This trend continues through (plant specific) systems should be addressed, or that plant specific electrical loads 1997, Rev IC, which does generically identify should be a plant specific (which covers one major cause of IA loss, compressors) not addressed. The WOG has always list. AFW and S/G level control specifics are needed in EOPs and the Deviation and recognized that plant specific information is to manage such information.
Background Document concepts were provided 1 the importance of AFW in At various times throughout the history of EOP-0.
has been recognized at PBNP. For general (but not mini recirc flow in particular) actuation was step number 1 of EOP-0.1.
example in Rev 7, 10/11/91, checking AFW 1995. Loss of IA due to electrical bus AFW pump runout concerns were added in For example in Rev 11, 11/22/94 (prior availability was addressed similarly to AFW.
for train specific equipment operation) to the development of AOP-18A and -18B Priority Electrical Loads, which included Appendix A to EOP-0.1 contained a list of when AOP-18A & -18B were created.
an IA compressor. Appendix A was deleted on ERG guidance. The ERGs Evaluation: PBNP EOP-0.1 is based appropriately need to be included in EOPs and consider that plant specific information may the same (Background and Deviation provides means and mechanisms to document (V&V) process described by the ERG documents). The verification and validation to identify plant specific needs to be procedure development process is intended did not include operator guidance in included in the plant specific EOPs. PBNP under a loss of IA condition.
EOP-0. I on AFW minimum recirc flow 15
RCE 01-069 Rev. 1 I Increased CDFin AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air Writers' Guide contains the usage OM 4.3.1, AOP and EOP Writers' Guide: The rules for notes and cautions that specify (in part):
necessary to
"* A note is used to present advisory or administrative information support performance of the subsequent step(s).
accomplish the purpose of
"* Each document should provide enough information to contained in notes or cautions.
the document without relying on information and not commands or
"* Notes and cautions should be declarative statements of fact to be taken in the event of action statements unless they are advising on actions changing plant conditions.
with the following results:
The references listed in OM 4.3.1 were reviewed Operating
"* NUREG-0899, Guidelines for the Preparation of Emergency with supplemental Procedures - 8/82: Note statements provide operators of steps in the EOP. These information concerning specific steps or sequences information, and be located so statements should provide operators with enough to the step or steps to which it as to ensure that they can easily relate the note should not direct operators to applies. Because they are supplemental, notes perform actions. (p24)
Program for
"* NUREG-1358, Lessons Learned From the Special Inspection many cases action statement were Emergency Operating Procedures - 4/89: In this increases the chance that the found embedded in notes and cautions. Again, occur. (p4) Cautions and notes are step will be overlooked and that an error will to warn of possible consequences not intended to direct operator action, but rather procedure steps. Inclusion of or to provide supplemental information to the and confusing to an operator. More actions in a caution or note can be disruptive if embedded in a caution or importantly, the action could be entirely overlooked actions, including conditional note. Any cautions or notes containing operator so as to provide an action step plus a actions or transitions, should be restructured caution or note. (pC-3) the Special Inspection
"* NUREG-1358, Supplement 1, Lessons Learned From
- 10/92: Cautions and notes:
Program for Emergency Operating Procedures and (2) no actions included.
notes (1) provide only supplemental information, (P16)
Operating Procedures in
" NUREG/CR-2005, Checklist for Evaluating Emergency notes avoid the use of action Nuclear Power Plants - 4/83: Do explanatory to perform actions must not be statements? (Statements directing personnel 7
imbedded in explanatory notes.) (p )
and notes shall NOT
"* PBNP Procedures Writers' Guide - 11/27/00: Cautions 5 actions. All required actions shall be stated in action steps. (p 0) direct or infer AOPs or EOPs.
This procedure is not applicable to the Because the present action step wording is
additional information is sometimes reduced to the minimum essential, certain included in a background document.
desired, or necessary, and cannot be merely or a CAUTION. (p )
22 is presented as either a NOTE This non-action information information necessary to NOTE is used to present advisory or administrative 16
RCE 01-069 Rev. I Increased CDFin AFW PRA Model Due to Procedural InadequaciesRelated to Loss of InstrumentAir or NOTE may also be support th6 following action instruction. A CAUTION in plant condition. As a used to provide a contingent transition based on changes not contain an instruction/operator general rule, a CAUTION or NOTE will CAUTIONS or NOTES, which action. However, passive action statements in may be appropriate under certain typically contain the words should, may or must, of a specific plant conditions. An example is when continuous monitoring condition and an associated action is required.
of a note is consistent with the WOG Evaluation: OM 4.3.1 guidance on the content other references cited. Some ERG Writers Guide, but contradictory to all of the the statement that "Each statements within the OM contradict others; specifically, to accomplish the purpose of the document should provide enough information in notes or cautions" contradicts document without relying on information contained to be taken in the event of changing the intent of "unless they are advising on actions plant conditions."
Training of the continuing training program is Continuing Training: The overall content determined based on a two-year cycle. Presently the 2001/2002 LOR (license Plan is in effect. The Long Range Plan operator requalification) Long Range Training respect to content of the topics to be concept is very organized and structured with The content of the Long Range covered; it has been used since the mid-1990s.
and includes a focus on systems Training Plan is based, in part, on PRA information Range Plan implementation, the with high safety significance. Prior to the Long a much less rigorous manner and on a content of LOR training was determined in week cycle. Content was based much shorter time frame, typically on a 6 week-to-6 and instructors plus inputs on needs suggested by students, operations management implementation, procedure changes, based on current events (such as design change plant and industry events).
pertinent to the issue of concern. The The 2001/2002 plan contains a number of topics Offsite Power were covered as well as a tasks for Loss of Instrument Air and Loss of training devices used by instructors to system review of Auxiliary Feedwater. The SGs (simulator guides). Both these cover the topics are LPs (Lesson Plans) and containing topical areas to be covered.
devices present information in outline form, environment, whereas SGs are targeted The LPs are primarily oriented for classroom operator. LPs clearly identify for the simulator, mostly the instructor/ simulator Typical support documents are references and materials to be used as handouts.
The LPs used in continuing training are the drawings, procedures and OE documents.
personnel indicated that LPs and SGs are same LPs used for initial training. Training of the individual trainer, are updated to reviewed prior to use and, to the best ability be current.
The highest-level document in Initial Initial Operator (CO and SRO) Training: position based. For example They are Training is the Program requirements (TRPR).
17
IncreasedCDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air TRPR 18 is Control Operator Trainee. The TRPRs are primarily administrative documents rather than technical. The TRPRs do identify the Training Courses (TRCRs) that comprise the Program. The TRCRs are a little more technical than Programs in that they identify some general areas of knowledge that the trainee needs to cover. For example, under TRPR 18, two of the courses are TRCR 52, Secondary Systems and TRCR 55, Integrated Operations. The TRCRs identify LPs. The LPs are the same as those used in continuing training. Some of the LPs specific to the event are LP 0169 AFW system, LP 0405 Reactor Trip or SI Response (which includes EOP 0.1), LP 0338 Instrument and Service Air (which includes AOP-5B) and LP 2439 Secondary Coolant System Malfunctions (AFW is one of those).
Evaluation: LPs contain enough specific information about auxiliary feedwater and instrument air systems to accurately describe system operations, causes and effects.
Training documents do not contain extremely specific details on specific evolutions.
For example, the specific method for controlling steam generator level as directed in EOP-0. I in concert with compounding events such as loss of IA, is not covered nor is the need to locally gag an AFW pump mini recirc valve upon loss of instrument air.
Instructors review material to be taught in advance and are able to make changes in course content in order to add information, including current events and to change areas of emphasis. The Simulator Guide topics used in continuing training appear to be marginally related to the topic area they are listed under. PRA and human performance information is not included in LPs. PRA and CDF values are used as input to select the content of the Long Range Training Plan for continuing training.
Other Documents DBD-01, Auxiliary Feedwater System Design Basis Document: Revision 0 of DBD-01 was issued on 4/4/94. In Section 4.8, AFW Pump Recirc Flow Control Valves, there was a statement under Safety-Related Functions that "These valves shall open automatically and remain open to provide a recirculation flowpath from AFW pump discharge to the CST when flow in the AFW discharge line is insufficient to prevent pump damage." The reference cited was MR 88-099. The DBD also stated "These valves shall close automatically to prevent the unnecessary diversion of AFW pump discharge during high-flow conditions where adequate pump discharge flow is removing pump heat." Section 4.8.4 addressed these competing requirements stating "Since this valve has a safety function to close, and a less significant function to open (long-term pump protection) it is most reliable therefore to have the valve fail (upon loss of power or instrument air) to the closed position. This section also discussed a potential worst-case flow condition with both the recirculation valve closed (due to loss of IA) and the associated discharge MOV closed (single active failure), but concluded that this was outside the system design and licensing basis.
This worst-case concern was based on NUREG-0800 assumptions, but was not considered applicable since PBNP had not incorporated NUREG-0800 into its licensing basis.
18
RCE 01-069 Rev. I Increased CDF in AFW PEA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air of the major changes included Revision I of DBD-01 was issued on 3/31/00. One valves for AFW was "Deleted safety-related function to OPEN for mini-recirculationDBD.
remained in the pumps." The worst-case flow condition discussion function for the Evaluation: The basis for including an OPEN safety-related 88-099, the modification that recirculation valves in Revision 0 was cited as MR pump protection. A review of increased the recirculation flow orifice size for AFW declaring a safety-related the modification paperwork did not identify any statement DBD validation documentation function for the valves to OPEN. A review of the recirculation valve position.
indicated that in-service testing of the valves checked was added to the IST Testing of the recirculation valves in the OPEN direction below.)
Program in 1991. (See discussion of IST Program function. This appears to be Revision 1 of DBD-01 deleted this OPEN safety-related later). Testing of the valves a result of actions coming from CR 97-3363 (discussed Program on 9/30/98, also as a result in the OPEN direction was deleted from the IST deleting this function to the DBD of CR 97-3363. Overall, the basis for adding and was not well documented or justified.
original EOPs issued in 1985 were EOP Verification and Validation (V&V): The using an approved procedure with a verified by a multi-disciplined verification team That effort generated over 2500 detailed checklist of attributes to be evaluated.
than 40 team meetings over a period discrepancy sheets and involved a series of more for EOP-0.1 did not raise any of several years. The discrepancy sheets generated or stopping feed flow to a S/G if a concerns with the step for controlling feed flow level increase above the desired value occurred.
of the basic version of the ERGs at The validation process involved a WOG review 1 ERGs at the Seabrook the Calloway simulator in 1982 and on the Revision plant specific procedures were taken to simulator in 1983. Early drafts of some of the which generated many suggested the Zion simulator in March and April of 1983, put through the previously described procedure changes. The procedures were then were used by operating crews at verification process. Following this, the procedures crew spent a week mitigating accidents the Kewaunee simulator (8/84-11/84). Each regarding the actions to control feed using the procedures. No concerns were raised above the desired level range. Finally, a flow or stop feed flow if S/G level increased review was expanded to provide another portion of the detailed control room design mock-up of the PBNP control room validation of the EOPs. A full size photographic from the typical 5 or 6) were evaluated was created and fourteen scenarios (increased used. Operators performed walkthroughs in an attempt to ensure that every EOP was were also videotaped for later review, and of the EOPs during these scenarios, which EOP-0.1 was validated using a Reactor then interviewed for their comments (1985).
loss of instrument air). Again, no Trip without SI scenario (without a concurrent to control feed flow or stop feed flow if concerns were raised regarding the actions range.
SIG level increased above the desired level 19
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I I InadequaciesRelated to Loss of Instrument Air The EOP V&V process was also part of a NUREG-0737 Supplement 1 (GL 82-33) commitment. The EOP procedure generation package (PGP) was submitted to the NRC on 6/1/84. The NRC responded with a draft SER on 517/87 that found the PGP to be unacceptable. The PBNP revisions to the draft SER were submitted back to the NRC on 11/10/87, addressing each of the identified concerns. The NRC issued the final SER on 4/9190 that contained additional programmatic improvements identified by the staff. The SER transmittal letter also referred to the June 1989 NRC Inspection of the EOPs and recommended that PBNP consider both the results of that inspection and the SER discussion and utilize them as appropriate in the next major revision of the EOPs. Current procedures governing the EOP V&V process are OM 4.3.2, EOP Verification Procedure, and OM 4.3.3, EOP Validation.
Evaluation: During the development of the PBNP EOPs from the WOG ERGs, information was to be included to address differences between the reference plant used by WOG and the Point Beach plant. Following development of those procedures, verification and validation reviews were applied to ensure the adequacy by of those procedures. Validation is the process of evaluating the EOPs for usability the operators and operational correctness (e.g., compatibility with plant hardware and control board layout). EOP-0.1 was operationally incorrect for a loss of IA condition.
Therefore, it was the validation step in the EOP development and implementation process that failed. The need to evaluate EOP-0.1 using a loss of instrument air condition was not recognized because the validation process did not evaluate procedures, design and human error/timeline analysis concurrently.
EPRI Report TR-100259, An Approach to the Analysis of Operator Actions in Probabilistic Risk Assessment - 6/92: This document is used by the PRA group in of evaluating human interactions for the probability of an error. It identifies attributes certain failure mechanisms that influence the overall probability that the mechanisms will contribute to a human interaction (HI). One mechanism, Relevant Step in Procedure Missed, has four attributes that are considered and evaluated in a decision tree:
"* Obvious vs. Hidden: Is the relevant instruction a separate, stand-alone numbered step, in which case the upper branch is followed, or is it "hidden" in some way that makes it easy to overlook, e.g., one of several statements in a paragraph, in a note or caution, or on the back of a page?
"o Single vs. Multiple: At the time of the HI, is the procedure reader using more than one text procedure or concurrently following more than one column of a flowchart procedure?
"* Graphically Distinct: Is the step governing the HI in some way more conspicuous than surrounding steps?
"* Place Keeping Aids: Are place keeping aids, such as checking off or marking through completed steps and marking pending steps used by all crews?
A hidden step had a 10% probability of being missed, whereas a procedure step by exhibiting the best of all four attributes had a probability of only 0.1%, a reduction 20
RCE 01-069 Rev. 1 IncreasedCDF in AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air 1.3%, which is a factor of 100. The worst probability for an obvious step is only about a factor of 8 lower than a hidden step.
line features FSAR: The FSAR did not include a description of AFW recirculation addition of involved the until updates were made in 6/97 and 6/98. The 1997 update line to the a paragraph describing the diversion of AFW flow via the recirculation an original design feature CST for a 3-minute period following pump start. This was AFW system. The 1998 that had never been included in the FSAR description of the the FSAR Review and Upgrade update was an extensive change resulting from system and its licensing Project that provided a more detailed description of the AFW an AOV controlled basis. This change added the wording that each pump had to ensure minimum flow to recirculation line back to the condensate storage tanks AFW flow period for dissipate pump heat. This change also revised the time diversion during pump start from 3 minutes to 45 seconds.
The original IPE for Point Individual Plant Evaluation, Revision 0 dated 6/30193:
as of 9/5/90. Many Beach was developed from a snapshot of the plant and procedures on design basis were based of the success criteria for systems in the IPE PRA model notebook for Auxiliary Feedwater, it was assumptions. In the original PRA system failed closed on a loss of recognized that the minimum recirculation flow valves PRA model as a failure mode instrument air. However, this was not included in the to open did not result in for AFW because it was assumed that these valves failing states:
pump failure. Assumption 22 in Section 4.6.7.1 of the notebook lines back to the CSTs.
The discharge lines of the AFW pumps have recirculation These lines are normally isolated by AOVs that fail closed on loss of power or pump start and when instrument air. Although they receive open signals upon a fail the AFW pump.
pump flow is low, it is assumed that failure to open does not to fail the Failure of one of these AOVs in a full open position is assumed associated AFW train due to diversion of pump flow.
flow was mentioned briefly in The potential to damage the AFW pumps with lack of the following discussion is the notebook. In Section 4.6.2.2 on Support Systems, found under the "Instrument Air" heading:
pumps (AF-4002)
The mini-recirculation valves on both the turbine-driven AFW fail shut on a loss of and the motor-driven AFW pumps (AF-4007 and AF-4014) on low flow instrument air. This could cause overheating of these pumps conditions with no recirculation flow available.
controlling (reducing)
These two sections seem to contradict each other. However, so there was plenty of time AFW flow was assumed to take place later in the transient was based on decay heat for the operators to perform this action correctly. This on ensuring that enough removal curves. Again, there appeared to be an emphasis not recognized how early in the flow was available in the transient initially and it was overfilling the Steam event that AFW flow needed to be reduced to prevent operator actions to control Generators. This is evidenced by Assumption 13 where 21
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air a
AFW flow later in the transient are discussed. No mention is made of ensuring minimum flow path is available:
Operator actions to control AFW flow later in an accident sequence are not explicitly modeled in the AFW system fault trees. Operator actions are necessary to prevent the AFW system from overfilling the steam generators as their pressures decrease and AFW flow likewise increases. This was not modeled since there is a long time available and the function would be alarmed.
In addition, the operator would have to successfully supply an alternate source of water to the suction of the AFW pumps (not automatic) and then forget to control flow or check steam generator level.
It seems from these statements in the notebook that some injection flow was always assumed to be required. The need for the operator to shut off flow to the Steam was Generators entirely from one or more AFW pumps at some time in the event apparently not considered.
In Section 4.6.4.2 of the notebook, initiating event impacts on the system are discussed. Under the "Loss of Instrument Air" heading, only the discharge valves for valves the motor driven pumps are considered. The closure of the mini-recirculation of for the AFW pumps was not documented as a possible effect of the Loss Instrument Air event:
A loss of instrument air will degrade the operators' ability to throttle the flow rates of that portion of the AFW system associated with the motor-driven AFW pumps.
The discharge pressure control valves, which are intended to limit flow to 200 of gpm per pump, (AF-4012, 4019) are air-operated and would fail open on a loss instrument air. Under this condition the operator is directed to use the turbine-driven pump to supply feed per AOP-5B, *Loss of Instrument Air (Reference 4.6-12) or use the local gag to control AF-4012 and AF-4019 per 01 62A, Motor-Driven Auxiliary Feedwater System (P-38A&B)".
for the The notebook also contains a discussion of potential common cause failures pumps minimum AFW system. This review did not identify the closure of each recirculation valve on a loss of instrument air as a potential failure mechanism.
to open However, this is consistent with the assumption that failure of these valves does not fail the AFW pumps.
of the plant Updates to the original IPE PRA model (1990) were based on snapshots to the long taken in 1993 and again in 1996, and implemented a few years later (due was to time required to perform the model update). The focus of these updates changes that incorporate new plant-specific failure data and to incorporate model this year is reflected plant modifications. The PRA model update being completed systems were examined from the first time since the original IPE effort that critical This was the ground up in a detailed review to ensure all failure modes are captured.
trees. Adding accomplished in part by use of detailed failure modes and effects fault model more this detail was considered to be necessary at this point to make the 22
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. 1 I InadequaciesRelated to Loss of Instrument Air flexible for fisk-informed applications. It was the use of this approach that identified the concern with operator actions to control AFW flow.
IST Program: In December, 1990 the 3rd interval program (Revision 0) was implemented. There is a line item in the general valve section that states "Due to isolation of S/G by EOPs, it may be necessary for an operating pumps recirc path to be available." The testing to verify the open function was not included in the tabular section of the IST program that identified the actual testing to be done. A valve program relief request (VRR-28) was added to the IST Program under Revision 1 on 5/28/91 that described the recirculation valves function to be "These valves open to ensure minimum recirculation flow from the pumps to prevent pump damage." A cold shutdown test frequency was being sought.
The NRC issued a Technical Evaluation Report (TER) on 4/17/92 that denied the relief request because the valves had a safety function in the closed position and noted that the recirculation valves were not tested by the IST Program in the open position.
The TER referenced the VRR-28 function statement and went on to state "The program should be revised to address these valves' safety function in the open direction." PBNP responded to the NRC on 7/30/92 to clarify that the valves could not be stroked except by use of hand wheels until modifications were made that allowed manual stroking using air. The response also stated "Since the AF pumps are capable of delivering feedwater at any steam generator pressure, the minimum flow valves are not required to open to protect the AF pumps under any anticipated accident conditions. The valves will, nevertheless, be stroke time tested in the open direction, as well as in the shut direction, once the modification to permit stroke time testing is completed." A follow-up letter dated 3/2/93, informed the NRC that the modifications would be completed by the completion of the spring 1993 refueling outage and VRR-28 relief request was being withdrawn. Revision 3 to the IST Program was implemented on 3/30193 deleting relief request VRR-28.
On 10115/97, CR 97-3363 raised a question about a discrepancy between the open function testing of the AFW recirculation line check valves (not in the IST Program) compared to the recirculation flow control valves (in the IST Program). The evaluation of this concern concluded on 2/5198 that there was no safety related function for the recirculation valves or check valves to open, and the IST Program would be revised. Revision 5 of the IST Program was issued on 9/30198 and deleted the open function testing of the recirculation flow control valves.
Interview Results Personnel Statements: Written statements were obtained from key personnel involved in the evolution of this issue covering the period of initial discovery to its reporting to the NRC. The information derived from those statements has been incorporated into the timeline included in Attachment B and involved the following personnel:
- PRA Engineer
- Design Engineer 23
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I ]
InadequaciesRelated to Loss of InstrumentAir
- Design Engiheering Manager
- Regulatory Compliance Engineer
- AFW System Engineer
- Operations Manager
- PRA Supervisor Interviews: Interviews were conducted with the following individuals to obtain additional information:
the PRA Engineer: An interview was conducted with the PRA Engineer that identified the concern with operator actions to control AFW flow. That interview identified following points:
- The PRA group reviewed the effect of the EOP change made (addition of foldout of page information) but did not make recommendations on the best method foldout page accomplishing the incorporation of that information. Use of the 0.05.
resulted in a reduction of the Human Error Probability (HEP) from 0.5 to credit for Use of a foldout page is treated as a continuous step with some additional of a CDF other control room personnel and training; it does not have as high reduction factor as a specific check.
- Credit was given in the recovery factor calculated for use of a procedure reader; it was treated the same as an extra crew.
- The PRA Engineer received information in June or July 2001 that operators stop obtained AFW flow by using valves versus stopping pumps. The information was later via during discussions with an operating crew. This information was verified operator interviews conducted by the HEP expert.
- The PRA group provides feedback to Training, via informal communications, on high high-risk accident sequences, but not on specific procedure steps that have HEPs.
and identified EOP Coordinator: An interview was conducted with the EOP coordinator the following points:
- The direct work item system is a process that allows procedure changes to be made.
by the Direct work items are changes that are issued by the WOG after review to the ERGs. Any appropriate WOG subcommittee. Essentially they are revisions does not become one member of WOG can initiate a possible direct work item but it until issued by the WOG.
- Changes to the EOPs can also be initiated internally without going through the WOG the EOP using the procedure feedback process. When this mechanism is used, to decide if it Coordinator and an Operations Procedure Writer evaluate the request defined should be processed, and the EOP set changed. There is no procedurally does not seem to be any process that describes the evaluation methodology. There 24
A1 IncreasedCDFin AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of InstrunientAir guidance on determining specific technical content of a change if it is outside the ERG.
- Foldout page content is expected to be memorized by the operator. Foldout page information is intended to trigger operator memory. The addition of foldout page information to EOP-0 and EOP-0. 1 is applicable at all times to continually control AFW flow correctly; this includes transition out of EOP-0 and EOP-0.1. The EOP Coordinator did not consider the PRA value of foldout page use versus other methods of incorporating the desired actions into procedures when the decision to use a foldout page was made.
- No formal V&V was performed on the foldout page change to the EOPs; a serial review was performed.
- The EOP Coordinator believes that Operations generally keeps Training informed of training needs.
- The EOP Coordinator thinks the changes made to the EOPs are done to streamline the procedures.
Other Information During preparations for the NRC Regulatory Conference held on this issue, discussions with the participants identified the following:
- The timing of operator actions for S/G level control assumed in the original IPE was based on decay heat curves. Diversion of flow (by gagging open the recirc valves) was not envisioned earlier in the accident scenario. The timing of operator actions to throttle AFW flow to a level requiring a recirculation flow path due to S/G overfilling or RCS overcooling concurrent with a loss of IA was not recognized.
- The EOP procedure weakness was very difficult to identify. It was only from an integrated perspective of evaluating AFW system design, procedural guidance, and FMEA, overlaid with human error probability analysis and timeline studies that the issue could be identified.
- The PBNP instrument air system has multiple cross-ties between units and redundancies that requires a dual unit event to cause a complete loss of IA. The EOPs are single-unit emergency procedures and do not consider dual unit casualties.
- During a SBO event, based on the required condition for decay heat (100% power for 100 days), the need to throttled AFW flow to levels requiring the recirculation valves to open would not occur for about 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, well after the time that IA is restored.
Therefore, the review of this event would not identify the EOP procedural vulnerability.
25
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of InstrumentAir Industry and Stafion Operating Experience Internal Operating Experience CR 97-3363, IST Program Design Basis for AFW Minimum Flow Recirculation Valves: This CR was initiated on 10/15/97 to address a concern with a conflict between the IST Program and the AFW DBD. The IST Program stated that the AFW recirculation line check valves did not have an active safety function to open and that the minimum flow recirculation lines were not needed since there was always adequate flow to the S/Gs under accident conditions. This conflicted with the AFW DBD that did not address the check valves, but had an open safety function for the recirculation valves. The IST Program tests the recirculation valves in the open and close directions. The DBD group performed an evaluation on 2/5/98 that concluded the check valves have no safety related function in either direction and that the recirculation valves only have a safety related function in the closed direction. The basis stated that the main safety related function of AF was to supply water to the S/Gs and that flow to the S/Gs was the most important flow path to maintain. The mini-recirc line was considered a diversion path, and since the AF system was capable of a cold start, a recirculation path was not necessary. The potential to deadhead a pump was considered, but establishment of a flow path through the discharge lines was used to eliminate the concern and the mini-recirc path was deemed to not be needed for pump protection. The evaluation noted that DBD-01 (Rev. 0) was being revised to reflect that there was no open safety function. The evaluation went on further to consider an AFW pump scenario where the associated discharge MOV failed to open or the pressure control valve inadvertently closed along with the recirculation path being blocked. In this event, the recirculation line would be required to prevent pump destruction, but the emergency function to feed the S/Gs is defeated anyway. This active single component failure scenario would only apply to one pump, so it would be acceptable and recirculation flow for AFW pumps was not a required safety related function.
QCR 99-0115, Code Testing Conflict With the Aux Feedwater Mini-Flow Recirc Check Valves: This CR was initiated on 5/24/99 and addressed a concern that conflicting information existed about the safety related function of check valves AF 115 and AF-1 17 to OPEN compared to the AFW recirculation valves that have a safety related function to CLOSE. Further, the IST Program did not include these check valves. An evaluation performed on 5/27/99 concluded that the concern identified was in error and had already been addressed by CR 97-3363. Additional evaluation on 6/15/99 concluded that some clarification to the IST Program documentation was needed to address how AFW single failure affected the decision on testing. A new action item was generated to revise the IST Program documentation and closed on 6/19/00 with issuance of Revision 4 of Appendix A of the IST Background Document.
- RCE 98-148, P-38A AFW Pump Recirc Valve Found Failed Shut, dated 1/29/99:
This RCE documented an event where an operator was in the process of starting an 26
IncreasedCDF in AFWV PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air AFW pump and noted that the recirculation line valve did not open as expected and then quickly secured the pump. This event showed that operators monitor recirculation valve position during AFW system manipulations.
INPO Operating Experience SEN 174 - Loss of Nonvital Bus Causes Dual Unit SCRAM and Degraded Auxiliary Feedwater System, dated 11110/97
Description:
At the McGuire plant, a loss of non-safety related 120V AC instrument and control power caused both units to SCRAM. Also, the recirculation valves for all 3 U-i AF pumps failed shut. The control board indication for these valves was also lost. As water level in the S/G was recovered, operators eventually shut the pump discharge valves. The pumps were operated for 20 to 60 minutes with their discharge and recirculation valves shut. Valve leakage was adequate to prevent pump damage.
Evaluation: This event is very similar to our case. Our evaluation of the SEN focused only on the power supply failure. AF pump operation without recirculation flow was discussed in the SEN and one question raised was "what procedures require operators to ensure that adequate pump flow is maintained?" This question was not addressed in the evaluation of the SEN. CARB requested that this SEN be reviewed again.
CA004279 was initiated to track this evaluation.
- SOER 88 Instrument Air System Failures, dated 5118188
Description:
This document provides a review and evaluation of industry events associated with failures and degradations of instrument air systems.
Recommendations 1, and 2 from this SOER are relevant to this event.
Recommendation 1 (Operations) was to provide procedures to assist operators in the identification, control, and recovery from partial or total loss of instrument air events.
A list of attributes that the operating, abnormal, and emergency procedures should provide included (in part) the following: identification of critical components operated by instrument air and the positions in which they fail, expected system and plant responses to a loss of IA and the consequences of these responses, actions to take if critical components do not fail in their intended position, and manual actions the operator should be expected to take to respond to a loss of IA event. The PBNP response was that AOP-5B, Loss of Instrument Air, contained the necessary instructions and information to assist operators in the identification, control, and recovery from partial or total loss of IA, and fully satisfied that recommendation. At that time, AOP-5B had an appendix for the AFW system that identified the recirculation valves as failing shut and requiring a manual gag override to open.
Recommendation 2 (Training) from the SOER was to provide classroom and simulator training on loss of IA events to operators. The training was to provide the bases for such things as failure modes of critical components and expected operator actions, so that the operators would understand the major concerns involved in a loss of IA event. The PBNP response was to initiate Training Needs Analysis (TNA) 88-27
IncreasedCDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. 1 I Inadequacies Related to Loss of InstrumentAir 0425 for the'PBNP Training group to evaluate. The result was that classroom training on loss of IA was included in cycle 89-8 of AO, RO, SRO, and DTA continuing training. LP 1782, Revision 0 dated 11/1/89, Instrument and Service Air was developed and approved to address this need. That lesson plan included a section that lists concerns with a loss of IA that focused on four areas: heat removal, auxiliary feedwater, inadvertent safety injection, and containment isolation. For AFW, the lesson plan identified that on the electric driven AFW pumps, the PCV fails open, and on all AFW pumps the recirculation valves fail closed. No simulator training on loss of IA was provided because PBNP was using the KNPP simulator then and loss of IA could not be adequately modeled on it.
Evaluation: The PBNP response to recommendation 1 addressed the need for information in abnormal operating procedures, but did not directly address operating and emergency procedures. The reliance on AOPs for addressing specific plant conditions and using EOPs for general response and mitigation probably influenced the scope of the review. The classroom training specifically identified that the AFW pump recirculation valves failed close on loss of IA, but did not identify concerns with pump damage or the need to gag open the valves, as dictated by AOP-5B.
However, there was a notation relating to the SI recirculation/test line isolation valves failing shut causing pump overheating in a few minutes and reference to an OPS Special Order 85-05 that had the valves currently gagged open. Simulator training was not performed due to modeling difficulties. Overall, the response did address the issue of the AFW recirculation valves failing closed on loss of instrument air. The reliance on AOP-5B for operator actions resulting from a loss of instrument air was reasonable based on what was known at that time.
OE 10727 - PRA Risk Insight to Improve Operator Actions, dated 9/11/00
Description:
This document describes an event at another utility where the NRC identified that they did not effectively use PRA risk insight to improve the timeliness and reliability of mitigating operator actions prior to an actual event resulting in loss of all RCP seal cooling to 2 RCPs. For this event, it was determined that PRA updates were not being used to train operators on plant vulnerabilities to core damage.
Evaluation: At PBNP, procedure ESG 5.1, PRA Maintenance and Update Guidelines, requires the generation of a condition report whenever new vulnerabilities are identified. However, there were no provisions in the ESG that addressed who should be trained. In response to OE 10727, a revision to ESG 5.1 was issued on 12/19100 that specified what groups should receive training on PRA updates and newly identified vulnerabilities.
Other Operating Experience Zion Station LER 90-002, 1A Auxiliary Feedwater Pump Cavitation, dated 2/15/90: This LER describes an event where the 1A turbine-driven AFW pump was of run in a deadheaded condition resulting in pump damage. Due to a combination both management error and procedural deficiency, the AFW pump was operated with 28
RCE 01-069 Rev. 1I Increased CDFin AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air about eight minutes the discharge ialve and recirculation valve shut for a period of an abnormal temperature until an operator stationed locally at the AFW pump noted and that the oil cooling rise on the pump's thrust bearing, water hammer sounds, pump damage can occur in water relief valve had lifted. This event demonstrates that condition. The pump a short period of time when operating a pump in a deadheaded impeller was found to be damaged and required replacement.
NRC Generic Communications Systems, dated 2/10/81 Generic Letter 81-14, Seismic Qualification of AFW the extent to which their The purpose of this GL was for licensees to determine non-seismic portions of the AFWS are seismically qualified and to walk-down the was submitted on July 16, system and identify deficiencies. Our original response adequately protected for a 1981, in which we concluded that the PBNP AFWS is AFWS recirculation valves or seismic event. No specific mention was made of the additional information dated piping. In a response to the NRC follow-up request for piping connections to the May 4, 1982, we specifically noted that the recirculation valves close upon seismic AFWS piping were inspected and that the recirculation Technical Evaluation Report receipt of a pump discharge flow signal. The NRC's AFWS did not provide (TER) of November 12, 1982, concluded that the PBNP a seismic event. In our reasonable assurance to perform its SR function following valves fail closed response dated December 15, 1982, we stated that the recirculation air system that instrument and the discharge AOVs fail open and concluded that the functioning. Because of the questions powers these valves is not required for AFWS we committed in this concerning the recirculation piping not being well supported, valve. Finally, in our letter to independently support each air operated recirculation request for comments on their letter dated April 26, 1985, we responded to the NRC during a seismic event of the revised TER. In the TER the staff postulated a failure recirculation valves to shut non-seismic AFWS piping or a failure of the pump water. In our response we following the switchover of the AFWS supply to service to recognize off normal stated that under either condition the operator are trained actions.
condition and that adequate time existed for manual operator the seismic adequacy of Evaluation: PBNP performed a design review that evaluated AFWS. Review of system foundations, supports and structures associated with the to the Generic Letter. Therefore, operating procedures was not a reasonable response the EOP procedural vulnerability.
this very specific design review would not identify at US Light Water Reactors, Information Notice 87-28, Air Supply Problems dated 6/22/87 of all systems that perform The internal evaluation of this IN consisted of a review for the effect that the loss of safety functions and contain air operated valve operators, positions of the AFWS valves air would have on those safety functions. The failure failure due to less than minimum are identified. The concern for pump damage or is also discussed. However, the pump flow with the recirculation valves failing shut the AFWS pumps would always focus of the evaluation was on demonstrating that 29
IncreasedCDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air feed the S/Gs with sufficiently high flow to protect the pump. This was documented in calculation N 87-041. At that time the discharge AOV for the electric AFW pumps failed open on loss of air; therefore, there was no identified concern with the recirculation valves failing shut.
Evaluation: PBNP verified the performance of safety-related functions with a loss of IA and that the AFW recirc valves must fail closed to assure the AFW safety-related function of providing flow to the S/Gs. It was also verified that adequate procedures existed (AOP-5B) to address a loss of IA, including the manual actions needed to gag open the recirc valves. Since PRA tools were not available yet, it is not reasonable that the EOP procedural vulnerability would have been identified.
- NRC Bulletin No. 88-04, Potential Safety-Related Pump Loss, dated 5/5/88 This bulletin requested licensees to investigate and correct as appropriate two mini Sflow design concerns. The first concern was the potential for deadheading one or more pumps that have a common mini-flow line. The second concern is whether or not the installed mini-flow capacity is adequate to prevent damage to safety related pumps. In a response dated June 28, 1988, we acknowledged that each of the pumps in the AFWS have their own recirculation lines with an AOV isolation valve and an orifice upstream of the common return line to the CST. We discussed the logic of the recirculation valves to open or shut dependent on AFWS forward flow but did not address the potential to lose recirculation on an instrument air failure. We also acknowledged that the flow orifice for the pumps will need to be replaced with higher flow orifices to ensure sufficient flow for indefinite pump cooling via the recirculation lines.
Evaluation: PBNP did a design review of the recirc capacity needed for adequate long-term protection of the AFW pumps. Modifications were initiated to increase the recirc flow capacity to the required levels. Review of system operating procedures was not a reasonable response to this Bulletin. Therefore, this very specific design review would not identify the EOP procedural vulnerability.
10 CFR 50.63 Loss of All Alternating Current Power, effective 7/21/88 The NRC amended its regulations at 10 CFR 50.63 to require all nuclear power plants to be capable of withstanding and recovering from a station blackout (SBO) of a specified duration. Our initial response to this regulation, which addressed the appropriate guidance from Reg. Guide 1.155 and NUMARC 87-00 was submitted on April 17, 1989. In that response we stated that no air-operated valves are required to operate to cope with a SBO for one hour. We also completed an analysis on condensate inventory necessary to cope with the one hour SBO. We concluded that we had sufficient CST inventory, along with the initial S/G fluid inventory to maintain SIG decay heat removal capability. Clearly, for a SBO, only the TDAFW pumps would be available. The concern appeared to be assurance that sufficient water would be fed to the S/Gs until AC power was restored and AFW could be shifted to the safety related service water supply. The first NRC SER on SBO was dated October 3. 1990. The NRC agreed, based on our statement, "that the 30
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. 1 InadequaciesRelated to Loss of Instrument Air compressed air is not needed to cope with an SBO for one hour and, after 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the Alternate AC power source will supply the compressed air." The Technical Evaluation Report (TER Page 16) also stated agreement that operation of the AFWS is independent of AC and IA for one hour. Indeed the concern identified in the Technical Evaluation Report was that the minimum volume of 10,000 gallons in the CST per unit, was insufficient and ultimately we had to revise our Technical Specifications to change that minimum CST volume to 13,000 gallons.
Evaluation: During a SBO event, only the TDAFW pumps are available (one per unit). The conditions for this event assume a decay heat load based on 100 days of operation at 100% power. Based on the high decay heat load and one TDAFW pump, it is not credible to stop or reduce AFW flow to a point where pump damage is incurred in the first hour. Therefore, it is not reasonable that the EOP vulnerability would have been found during reviews associated with a SBO event.
Generic Letter 88-14, Instrument Air Supply System Problems Affecting Safety Related Equipment, dated 8/8/88 In a February 20, 1989, response to this GL we stated that all safety related pneumatic equipment at PBNP is designed to fail to a safe condition with the safety function being tested in the PBNP IST Program. The AFWS discharge AOVs were specifically discussed and the concern expressed that the fail open position could potentially lead to over feeding of the S/Gs. There was additional correspondence to the NRC on July 27, 1989, in the form of a supplemental response concerning the potential problem with the discharge valves failing open. We also responded to an inspection report dated January 16, 1991, in which the NRC determined that PBNP had not fully complied with statements in our original GL response regarding testing of safety related AOVs. In this response we clarified that safety related valves with "passive" functions (do not perform a mechanical motion during the course of accomplishing a system safety function) were excluded from IST fail safe testing.
We also noted that since the 1989 submittal the IST program was revised and reissued for the third 10-year interval and that the AFWS mini-recirculation valves were now fail safe tested.
Evaluation: PBNP verified the performance of safety-related functions with a loss of IA and that the AFW recirc valves must fail closed to assure the AFW safety-related function of providing flow to the S/Gs. It was also verified that adequate procedures existed (AOP-5B) to address a loss of IA, including the manual actions needed to gag open the recirc valves. Since PRA tools were not available yet, it is not reasonable that the EOP procedural vulnerability would have been identified.
Generic Letter 89-04, Guidance on Developing Acceptable In-service Testing Programs, dated 4/3/89 The attachment to the GL listed eleven specific generic deficiencies related to IST programs and procedures. Item 9 addressed pump testing using minimum flow return line with or with out flow measuring devices. The concern for this item was for those pumps that could only be IST tested using minimum flow return. In our response 31
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrunment Air in compliance dated Octobei 3, 1989, we confirmed that SI, RHR and AFW are tested for with the GL position 9. The GL advised licensees that meeting the guidelines (See discussion above).
Code testing does not supercede the thrust of Bulletin 88-04 opportunity for Evaluation: This review of this issue does not appear to be a missed evaluation of the EOP procedural vulnerability.
Evaluation Methodology & Analysis Techniques The analytical techniques used in this root cause evaluation were:
- Document Review
- Interviewing
- Event and Causal Factor Charting (Attachment D)
- Timeline Development (Attachment B)
- Why Staircase Development (Attachment C)
Data Analysis Summary Identification of Causal Factors obtained in the Information A "Why Staircase" was constructed based on the information in a repetitive asking of the
& Facts Sources section of this report. This technique results obtained. The "Why question "why" until a detailed understanding of the problem is identified three Staircase" for this event is provided in Attachment C. This approach main causal factors that contributed to this event.
of RCS cool down EOP-0.1 contains a step (step 1) to CONTROL feed flow because a steam generator if an considerations and another step (step 4) to STOP feed flow to
- these steps do not increasing level cannot be maintained below the desired setpoint (It is postulated that an specify the method to be used to CONTROL or STOP flow.
a loss of instrument air operator could throttle the AFW discharge valves closed and with would dead-head and when the recirculation valves are failed closed, the running pumps mode failure.)
destroy themselves in short period of time; a potential common was not provided in the There were two reasons influencing why specific information specific operator actions EOP. First, reliance had been placed on AOP-5B for providing the AFW discharge valves for a loss of instrument air scenario, and second, closure of failure mechanism.
due to operator action was not previously considered as a possible Reliance on AOP-5B:
to control AFW flow (under loss Reliance on AOP-5B was faulty because operator action of EOP-0.1. This need had not of instrument air conditions) was needed in the early steps have identified this need was via been identified prior to this event. A key opportunity to EOP-0.1 steps was done in 1985 the EOP validation process. The original validation of include a concurrent loss of using a Reactor Trip w/o SI scenario. This scenario did not what method an operator instrument air condition. Consequently, it would not matter 32
-. . . . . . . ..- - I Increased CDF in AFWPRA Model Due to Procedural RCE 01-069 Rev. I I InadequaciesRelated to Loss of InstrumentAir used to control flow since either throttling flow or shutting off pumps would be successful. These steps have not changed since Revision 0, so additional validation would not have been required. It was the EOP validation barrier that failed. Validation was to ensure the operational correctness of the EOPs. The reason the barrier failed was because the interaction between design, procedures, and human error/timeline analysis was not evaluated concurrently, and the need for specific operator actions under a loss of instrument air condition was not recognized. The Human Error/Timeline Analysis method was not available at the time the EOPs were originally validated.
Another key opportunity to identify the need for operator action while in EOP-0.1 was when the initial PRA model was developed to support the IPE submittal in 1993. The original PRA model did not model operator actions to control AFW flow in the system fault trees because it was assumed (based on decay heat removal requirements) that there was a long time available and the function (S/G overfill) would be alarmed (assumption 13). The flaw in this assumption was not identified during the PRA model review because the fault trees were based primarily on functions described in design documents.
Also, only operator actions taken to mitigate a failure were evaluated. The selection of the evaluation method using fault trees focused on design functions over other FMEA methods was based on an assumption that the design function approach was more conservative. The current PRA model review uses a methodology that integrates system performance with potential human actions to obtain a spectrum of plant responses. The original PRA Model was based on system functions, and only operator actions to mitigate failures were evaluated.
Finally, routine performance of accident scenarios on the PBNP simulator should also have provided an opportunity to identify this need for operator action. Simulator Guides are presented in outline form and do not contain detailed information on evaluation of all actions performed during the scenario. PRA information has been used to identify which scenarios are important to teach from a risk perspective, but information on which steps in emergency procedures are risk-significant has not been incorporated into scenario evaluation criteria. The operator action to control AFW flow had not been identified as a human interaction with a human error probability assigned to it (because Human Error/Timeline Analysis was not available yet). Consequently, scenarios often went quickly through the loss of air condition to other conditions such as loss of secondary heat sink without evaluating the intermediate steps such as S/G level control. The interface between the PRA and Training programs is less than adequate.
Operator Action was not Previously Considered as a Possible Failure Mechanism Previous evaluations of the effects of the AFW recirculation valves failing closed on loss of IA concluded that the AFW pumps would not be damaged because forward flow was always available. Closure of a single discharge valve due to component failure considered concurrent with the AFW recirculation valve failing closed was evaluated and to be outside the design and licensing basis. (This used NUREG-0800 assumptions and PBNP was not committed to that NUREG.) Closure of all the discharge valves due to operator action was not considered. The two reasons identified for not considering 33
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I I InadequaciesRelated to Loss of InstrumentAir into failure mode analyses operator actions w~ere the lack of integrating human actions result in pump damage.
and the lack of insight that a specific operator action could result from human Although the concept of determining the potential failures that could most often utilized in the PRA errors has been around since at least the TMI accident, it is of failure modes from a area. The current design process does not prompt an evaluation AOVs were modified human action perspective. When the MDAFW pump discharge created that did not exist on with a nitrogen back-up system, a throttling capability was of the MOVs that that valve before (under a loss of instrument air condition). Throttling existed, so this was an direct AFW flow to the respective steam generators had already component. Only recent additional opportunity to perform that same action on another allowed identification of the use of failure mode fault tree tables in the PRA program evaluating human interactions in concern on AFW control. The knowledge learned from modes and effects analysis the PRA program has not been transferred into the failure the PRA and Design element of the design control program. The interface between Control programs is less than adequate.
to a "CONTROL or Insight was needed to understand that the actual operator response scenario would be closure of STOP feed flow" command under a loss of instrument air The expected operator the discharge valves instead of stopping the AFW pumps.
under a loss of instrument air response to the "CONTROL or STOP feed flow" command that operation of the scenario was not clearly stated in training documents. Knowledge it could have with AFW discharge valves had a human error probability associated identified the potential for resulted in focused training on that evolution that may have human interactions was not pump damage. However, the information on risk-significant interface between the PRA and effectively incorporated into the training program. The Training programs is less than adequate.
Other Conclusions interactions are based on The assumptions used by the PRA group in evaluating human of procedures is established.
industry guidelines that determine how the effectiveness procedure writing. One These same rules have not been applied to our process for guidance is clearly not to example is the use of action steps in notes. The industry Writers' Guide (and WOG ERG include actions in notes. However, the AOP and EOP that initiates an action in a note.
Writers Guide) allows the use of condition monitoring in a note. Procedure Under PRA rules, little credit is given for an action embedded rules into our procedure effectiveness can be improved by incorporating PRA PRA and procedure development development process. The interface between the processes is less than adequate.
the governing document for ESG 5.1, PRA Maintenance and Update Guideline, is interfaces with departments administration of PRA updates. That procedure contains may be more appropriate for outside of Engineering. The use of a higher tier document update process lack formality.
this process. Organizational interfaces for the PRA 34
- I increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. 1 InadequaciesRelated to Loss of InstrumentAir basis and licensing documents There was a lack 6f consistency between different design recirculation valves. The regarding the description and function of the AFW correspondence was that AFW flow predominant position taken in various licensing valves were not required to could always be provided to the S/Gs and the recirculation AFW DBD (1994) contained a provide an open safety function. However, the initial and the basis was not clear. The statement that the valves had an open safety function, in 2000. The IST program did not open function was removed from the AFW DBD in the open direction based on include an open safety function, but did test the valves was removed from the IST program in prior NRC correspondence (1992). That testing of the recirculation line function until 1998. The FSAR did not include any discussion AFW licensing and design updates made in 1997 and 1998. Consistency between basis documents is less than adequate.
was part of many prior evaluations.
The subject of AFW flow and recirculation capability procedures and human error timeline However, the combined evaluation of design, model update process. Without the use of analysis only occurred during the recent PRA that previous evaluations would have these combined analyses, it was not reasonable identified this vulnerability.
FailureMode Identification
- Actions required by RR5 Actions Not Tied to Another Process When Necessary is needed to ensure one program not belonging to any program, which consistency.
was not effectively
"* Information on risk-significant human interactions including scenario incorporated into the operations training program, development in the PRA program
" Knowledge learned from evaluating human interactions and effects analysis element of has not been transferred into the failure modes the design control program development
"* PRA concepts are not included in the emergency procedure process AFW system was not
" Consistency in the licensing and design basis for the IST program maintained between the FSAR, AFW DBD and 7
RR2 Actions Not Clear - Inade uate program design in 1985 using a Reactor Trip The original validation of EOP-0.1 steps done loss of instrument air condition w/o SI scenario did not include a concurrent Analysis) needed to because the analytical tools (Human Error/Timeline identify this were not available at that time
- Lack of interface F2 Inadequate Communications Among Organizations formality 35
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I I InadequaciesRelated to Loss of Instrument Air 0 The PRA update interface requirements with other organizations are contained in an Engineering Supplemental Guideline, and lack formality
-J4 Wrong Assumptions - Erroneous assumptions used in decision making Only operator actions taken to mitigate failures were evaluated in the original PRA model The selection of the original PRA model evaluation method using fault trees focused on design functions over other FMEA methods was based on an assumption that the design function approach was more conservative VII. Root Causes & Contributing Factors Conclusions causing The investigation found that the EOP validation process is the barrier that failed, the weakness in EOP-0.1. The EOP validation process failed because it did not evaluate only the interaction among design, procedures, and human error timeline analysis. It was from this integrated perspective that a loss of instrument air causing the recirculation valves to fail closed, combined with a possibility that an operator would close the discharge valve on an AFW pump, and the timing of this action prior to implementation be of the abnormal procedure for loss of instrument air (AOP-5B) could the potential and seen to damage multiple AFW pumps. The combination of FMEA, timeline studies, industry unique to PRA.
human error analysis is a recently implemented practice in the Without the use of these combined analyses, it was not reasonable that previous evaluations would have identified.this vulnerability.
Root Cause EOP The root cause of the EOP procedural weaknesses was the failure of the original to validation process barrier to identify that specific operator actions were needed air condition. This barrier properly control or stop AFW flow under a loss of instrument not exist at that failed because the analytical tools needed to identify this vulnerability did time. This resulted in a misalignment between plant design and procedural guidance.
Contributing Causes Significant contributing causes to this condition continuing to exist were:
- The original PRA model fault trees evaluated system performance primarily on actions functions described in design documents and only considered operator taken to mitigate a failure
- Previous evaluations focused on delivery of the minimum required AFW flow for providing decay heat removal 36
~-~~-,r~7
~ I I IKLL u- - xxe V.
Increased CDF in AFW PRA Model Due to Procedural L .Il InadequaciesRelated to Loss of InstrumentAir were:
Other causes that were not significant contributors reviews in the design control
"* The failure to consider human actions during FMEA processes, methods into the operations
- The lack of integration of human error reduction training process, methods'into the emergency
"* The lack of integration of human error reduction procedure development process, in the PRA update process, and
"* The lack of formality of organizational interfaces DBD, and the IST program
"concerningthe description and function of Vill. Corrective Actions Interim Corrective Actions (mitigation)
Due Date: Complete CA #1 Responsible Group: Qperations, Completion AFW control under loss of Revise EoP-0, EOP-0.I and ECA-0.0 to aadress instrument air conditions.
(CATPRs)
Corrective Actions to Prevent Recurrence Priority: 2, Completion Due Date:
o CA #1 Responsible Group: Engineering (PRA),
Complete [CA003691]
the EOP initiating events should be included in Assist Operations in determining what events information on which initiating validation process by formally providing considered risk-significant for each EOP.
2, Completion Due Date: 8/512002
- CA #2 Responsible Group: Operations, Priority:
[CA003692]
(90 days after CATPR #1 is completed) are ensure that appropriate initiating events Revise the EOP validation process to what initiating events are applicable.
included. Utilize PRA input in determining 37
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air Corrective Actiors to Restore (broke - fix)
"* CA #1 Responsible Group: Engineering (PRA), Priority: 3, Completion Due Date:
10/4/2002 [CA003693]
Complete the analysis portion of the PRA model review to identify any other risk significant vulnerabilities in the current EOPs.
"* CA #2 Responsible Group: Operations, Priority: 3, Completion Due Date: Complete
[CA003694)
Review the operator actions specified in AOP-5B to determine if they should be included in applicable EOPs to ensure timeliness of the actions, and initiate revisions as required.
"* CA #3 Responsible Group: Engineering (PRA), Priority: 3, Completion Due Date:
6/5/2002 [CA003695]
Formally provide Operations and Training with an updated list of high-risk human error events based on the PRA model.
" CA #4 Responsible Group: Engineering (PRA), Priority: 3, Completion Due Date:
6/5/2002 [CA0036963 Formally provide Operations and Training with a description of the human error reduction methods used in evaluating operator actions in the PRA model.
" CA #5 Responsible Group: Operations, Priority: 3, Completion Due Date: 10/4/2002 (120 days after CA #2 and CA # 3 are completed) [CA003697]
Review EOPs and AOPs containing high-risk human error events against human error reduction methods used in the PRA model and revise where appropriate to achieve significant CDF risk reduction.
" CA #6 Responsible Group: Operations, Priority: 3, Completion Due Date: 10/4/2002 (120 days after CA # 3 is completed) [CA003698]
Revise OM 4.3.1, AOP and EOP Writers' Guide, to incorporate human error reduction methods used in the PRA model that can significantly reduce CDF risk.
" CA #7 Responsible Group: Training, Priority: 3, Completion Due Date: 10/4/2002 (120 days after CA #2 and CA # 3 are completed) [CA003699]
Review initial operator training materials and methods associated with high-risk human error-events against human error reduction methods used in the PRA model and revise where appropriate to achieve significant CDF risk reduction.
38
N Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I I InadequaciesRelated to Lbss of InstrumentAir
" CA #8 Responsible Group: Training, Priority: 3, Completion Due Date: 10/4/2002 (120 days after CA # 3 is completed) [CA003700]
Revise operator training procedures to incorporate human error reduction methods used in the PRA model that can significantly reduce CDF risk.
"* CA #9 Responsible Group: Engineering (PRA), Priority: 3, Completion Due Date:
6/5/2002 [CA003701]
Revise the AFW PRA model to accurately reflect system performance.
"* CA #10 Responsible Group: Engineering (Systems), Priority: 3, Completion Due Date: 6/5/2002 [CA003702]
Review the description of the AFW recirculation line function in the FSAR, DBD-01, and the IST Program for consistency and accuracy, and initiate revisions as required.
"* CA #11 Responsible Group: Engineering (Design), Priority: 3, Completion Due Date:
6/5/2002 [CA003703]
Revise the design process to include consideration of human action induced failure modes.
"* CA #12 Responsible Group: Engineering (PRA), Priority: 3, Completion Due Date:
6/5/2002 days [CA003704]
Evaluate if an Engineering Supplemental Guideline is the appropriate procedural method for controlling PRA updates, or if a higher tier document such as a Nuclear Procedure (NP) should be used considering the interfaces involving other departments. Initiate any procedure changes resulting from that evaluation.
"* CA #13 Responsible Group: Engineering (PRA), Priority: 3, Completion Due Date:
6/5/2002 [CA003705]
Revise the procedure governing PRA updates to include identification of the formal methods to be used for providing information to other groups. Use of existing processes, such as training work requests and procedure feedback forms, should be used whenever possible.
"* CA #14 Responsible Group: Assessment, Priority: 3, Completion Due Date:
Complete [CA003982]
Review SEN 174 response and re-open the OE items if not fully addressed.
39
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rxev. J InadequaciesRelated to Loss of Instrument Air
" CA #15 Responsible Group: Operations, Priority: 3, Completion Due Date: Complete
[CA004279]
adequate pump Review SEN 174 and verify that procedures exist for maintaining flow, including pumps other than AFW.
Due Date:
" CA #16 Responsible Group: Engineering (PRA), Priority: 4, Completion Complete [CA004388]
validity for the top risk Review operator action assumptions in the PRA model for significant systems.
Complete
" CA #17 Responsible Group: Training, Priority: 3, Completion Due Date:
due to less than required Update the PBNP simulator to model AFW pump failure minimum recirculation flow.
Due Date: Complete
" CA #18 Responsible Group: Operations, Priority: 3, Completion Revise the EOP validation process to include PRA involvement. OM/L43 / Od*./-l '
Completion Due Date:
"* CA #19 Responsible Group: Engineering (Design), Priority: 3, Complete pneumatic supply to allow Modify the AFW recirculation valves to provide a back-up time for operator actions.
IX. References AOP-5B, various revisions, Loss of Instrument Air for AFW Minimum Flow CR 97-3363, dated 10/15/97, IST Program Design Basis Recirculation Valves of Instrument Air CR 01-2278, dated 7/6/01, AFW PRA Model for Loss CR 01-3595, dated 11/29/01, PRA for AFW System to an Appendix R Fire CR 01-3633, dated 12/4/01, Response of MDAFWPs Failure Information for CR 01-3641, dated 12/4/01, AFW Pumps Common Mode CR 01-3595 RCE to an Appendix R Fire CR 01-3648, dated 12/5/01, Response of MDAFWPs Opportunity CR 01-3654, dated 12/6/01, AFW System DBD Missed System DBD-01, Revision 0, dated 4/4/94, Auxiliary Feedwater Feedwater System DBD-01, Revision 1, dated 3/21/00, Auxiliary
- Reactor Trip or Safety Injection DD-EOP-0, various revisions, Deviation Documents EOP-0, various revisions, Reactor Trip or Safety Injection EOP-0. 1, various revisions, Reactor Trip Response the Analysis of Operator Actions EPRI Report TR-100259, dated 6/92, An Approach to in Probabilistic Risk Assessment 40
RCE 01-069 Rev. 1 Increased CDF in AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air Event Notificatior Worksheet EN#38525, dated 11/29/01 dated 11130/01 Event Notification Worksheet EN#38525 Supplemental, System (AF)
FSAR, Chapter 10, various revisions, Auxiliary Feedwater Individual Plant Evaluation, Revision 0, dated 6/30/93 IST Background Document -Appendix A, dated 5/17/00 IST Program - 3 rd Interval, various revisions Reportability Recommendations Internal Memorandum, dated 12/3/01, CR 01-3595 of Emergency Operating NUREG-0899, dated 8/82, Guidelines for the Preparation Procedures the Special Inspection Program for NUREG-1358, dated 4/89, Lessons Learned From Emergency Operation Procedures Learned From the Special Inspection NUREG-1358 Supplement 1, dated 10/92, Lessons Program for Emergency Operation Procedures Emergency Operating NUREG/CR-2005, dated 4/83, Checklist for Evaluating Procedures Used in Nuclear Power Plants dated 12/1/01 OD 01-3595 Rev. 0 dated 11/30/01, and Rev. I OD 01-3648 Rev. 0 dated 12f7/01 Writers' Guide OM 4.3.1, Revision 1, dated 6/4/99, AOP and EOP Procedure OM 4.3.2, Revision 1, dated 6/14/95, EOP Verification OM 4.3.3, Revision 0, dated 7/30/93, EOP Validation 1991 PRA System Notebook - AFW, Revision 0, dated With the AFW Mini-Flow Recirc QCR 99-0115, dated 5/24/99, Code Testing Conflict Check Valves Recirc Valve Found Failed Shut RCE 98-148, dated 1/29/99, P-38A AFW Pump (Draft Report - 7/01)
S-A-ENG-01-03, PBNP PRA Peer Review Report Causes Dual Unit Scram and Degraded SEN 174, dated 11/10197, Loss of Nonvital Bus Auxiliary Feedwater System WOG ERG Executive Manual WOG ERG Writers Guide, dated 711/1987 WOG LP-ERGs IA Auxiliary Feedwater Pump Zion Station LER 050-295/90-002-00, dated 2/15/90, Cavitation X. Attachments Attachment A: Team Charter Attachment B: Timeline Attachment C: Why Staircase Attachment D: Event & Causal Factor Chart 41
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I I InadequaciesRelated to Loss of Instrument Air Attachment A: Team Charter Root Cause Investigation Charter CR 01-3595 RCE 01-069 Issue Manas!er:
Rick Mende Problem Statement:
transients involving loss of Discovery during the review of the AFW PRA model for procedures may not adequately instrument air-that emergency and abnormal operating flow to prevent AFW pump address maintaining minimum AFW pump recirculation failure.
Investigation Scope:
Determine the following:
- the root cause of why the condition exists
- why the problem was not identified previously Make recommendations for:
- correcting the problem
- preventing recurrence of the problem condition)
- applicability of the root cause to other areas (extent of Team Members:
Team Leader - Richard Flessner, Engineering Processes Team Member - R. Wood, PRA Team Member - J.P. Schroeder, System Engineering Team Member - T. Staskal, Site Assessment Team Member - C. Krause, Licensing Milestones:
Status Update - 12/11/01 Draft Report - 12/20/01 Final Report - 1/ 10102 Approved: (Original sianed by F. Cavia) Date: 12/4/2001 Fred Cayia, PBNP Plant Manager 42
Increased CDF in AFW PRAi Model Due to Procedural RCE 01-069 Rev. I I InadequaciesRelated to Loss of Instrument Air Attachment B: Event Timeline DATE / TIME DESCRIPTION 911/79 M-623/624 TDAFP alternate bearing cooling supply modification issued 2/1/80 IC-274 AFW recirculation valve logic (keep open) modification issued 2/10/81 GL 81-14 issued on Seismic Qualification of AFW System (response is dated 7/16/81) 5/4/82 Additional response to GL 81-14 due to NRC RAI - response says that AFW recirc valves close on receipt of AFW pump discharge flow signal 6/82 WOG Basic ERGs validated on Calloway Simulator 8/82 NUREG-0899, Guidelines for the Preparation of EOPs, is issued 8/31/82 IC-274 AFW recirculation valve logic (keep open) modification cancelled 11/12/82 NRC issues TER concluding that PBNP AFW system did not provide reasonable assurance to perform its SR function following a seismic event 12/15/82 PBNP response to NRC TER on AFW - concluded that IA is not required for AFW system functioning (based on recirc valves FC and discharge valves FO);
commit to independently supporting each recirc valve 4/83 NUREG/CR-2005, Checklist for Evaluating EOPs, is issued 8/1/83 MR 83-104 AFW system discharge MOV controls modification issued 4/26/85 PBNP response to revised NRC TER on AFW - conclude that AFW piping failure or failure of AFW recirc valves to close will be handed by operators trained to recognize off normal condition that adequate time exists for manual action 7/1/85 Revision 0 of the EOPs issued 5/2/86 AOP-5B, Loss of Instrument Air, Revision 0 issued 6/22/87 IN 87-28 issued on Air Supply Problems at US Light Water Reactors 7/1/87 WOG ERG Writers Guide issued 12/20/87 IN 87-28 Supplement 1 issued on Air Supply Problems at US Light Water Reactors 3/23/88 NPERS evaluation of IN 87-28 issued via NEPB 88-090 5/5/88 IEB 88-04 issued on Potential SR Pump Loss (response is dated 6/28/88) 5/18/88 INPO issues SOER 88-01 on Instrument Air Failures 7/7/88 MR 88-099 AFW pump mini-recirculation line improvements modification issued 7/21/88 SBO Rule (10CFR50.63) became effective (response is dated 4/17/89) 8/8/88 GL 88-14 issued on Instrument Air Supply System Problems Affecting SR Equipment (response is dated 2/20/89) 4/89 NUREG-1358, Lessons Learned From the Special Inspections Program for EOPs, is issued 4/3/89 GL 89-04 issued on Guidance on Developing Acceptable IST Programs (response is dated 10/3/89) 5/8/89 MSS approves response to SOER 88-01 2/15/90 Zion Unit I LER issued on AFW Pump Cavitation 12/90 3 'r interval IST Program is implemented
--1991 Original IPE Notebooks developed 43
Model Due to Procedural RCE 01-069 Rev. 1 Increased CDF in AFW PRA Air InadequaciesRelated to Loss of Instrument DESCRIP DATE/TIME on recirc valves 5/28/9I Revision I to IST Proram adding VRR-28 VRR-28 and requesting OPEN 4/17/92 NRC issues TER on IST Program denying safety function be added for recirc valves to the Analysis of Operator Actions in 6/92 EPRI Report TR-100259, An Approach PRA, is issued AFW recirculation line AOVs 6/19/92 MR 92-091/092/093 IST testability of modifications issued that recirc valves are not required to 7/30/92 PBNP response to NRC TER clarifying -ur OPEN to rotect AFW s Learned From the Special Inspections 10/92 NUREG-1358 Supplement 1, Lessons Progam for EOPs, is issued completed for testing recirc valves and 3/2/93 PBNP informs NRC that mods will be "withdrawsVRR-28 3/30/93 Rev. 3 of IST deletes VRR-28 and recirc valves DBD-01 validation considers worst-case flow (discharge 4/93 basis closed) outside desi and licensing 6/30/93 Revision 0 of IPE PRA model is issued issued 4/4/94 DBD-01, AFW S stern, Revision 0 is EOPs
-1995 Affects of excessive AFW flow introduced into control valve backup nitrogen 4/15/97 MR 97-038*A/B MDAFP discharge pressure issued su I and cable separation modifications start date to FSAR addingAFW recirc feature for 3 minute closure on urn 6/97 U from appendices to AOP-5B, Revision 11 issued that moved time critical steps 9/26/97 main bod nf the rocedure Revision 1C of WOG ERGs issued 9/30/97 Design Basis for AFW Minimum Flow 10/15/97 CR 97-3363 initiated on IST Program Recirculation Valves (closed 10/5/98)
SEN 174 on Loss of Nonvital Bus Causes Dual Unit Scram and 11/10/97 INPO issues De ded AFW Systern (McGuire Units) 1998 U date to PE P-RA model is issued supplies and did not Evaluation of SEN 174 completed - focus was on power 1/6/98 description of recirculation line function.__
valves date to address U._ of AfW recirculation FSAR addingdetailed degradation 6/9-'-8 Recirc Valve CR 98-2575 (RCE 98-148) initiated on P-38A AFW Pump 6129/98 Found Failed Shut-- valves in the "R~ev. 5 of IST Program, issued deleting testing of AFW recirc 913/9'-----
o__en direction AFW Mini-flow QCR 99-0115 initiated on Code Testing Conflict With the 5/24/99 Recire Check Valves is issued 3/31/00 DBD-01, AFW S.stem, Revision 1 involvingPRA 9/11/00 OE 10727 initiated on industry event 44
-J RCE 01-069 Rev. I I Increased CDF in AFW PRA Model Due to Procedural InadenuaciesRelated to Loss of hIstrument Air DESCRIPTION DATE / TIME model for the 7/6/01 While revising the Probabilistic Risk Assessment (PRA) was identified Auxiliary Feedwater system, a potential procedural shortcoming 01-2278 was originated in AOP-5B, Loss of Instrument Air. Condition Report to document the above finding A CR action was created item #1Air," for Operations to move the step in AOP-5B, open the AFW minimum recirculation 7/101/01 "Loss of Instrument for gagging (CR 01-2278) valves to an earlier location in the body of the procedure.
run an evaluation to 7130/01 Operations discussed issue with PRA group. PRA to determine the significance of the issue. Analysis was expected to be completed by 8/20101 (CR 01 -2278) to determine the The analysis is not ready yet. The evaluation is expected 8/20/01 the type of actions that actual risk significance of the condition and address maybe recommended. (CR01-2278) is showig a higher risk 10/19/01 Per discussion with the PRA group, the PRA model should lossprocedurally the be dir. PRA The addressed. AOP Group is is and sequenced properly tovalve the recirculation address of instrument be changed to address requesting that the ARP for low instrument air pressure the sequence of the this concern. This should be adequate rather than changing (CR 01-2278)
AOP. PRA will follow up with a procedure feedback.
to create a new action CR 01-2278 Action #1 was completed with direction 10/24/01 1-9 for low instrument air item to track issuance of a change to ARP C01 A pressure. (CR 01-2278) whether procedure Operations had discussions with PRA Group regarding Early November, changes were adequate.
2001 Week of Nov 13th' 2001 11/26/01 j PRA Group went to work to adjust the PRA model procedure change was not complete or would not Modeling adjustments were completed. A risk to evaluate the risk if the be adequate.
evaluation was done for the risk increase was identified.
minimum recirculation valves. A factor of 2.3 discussion was held with This was considered high-risk significance. A and Engineering. Decided we needed to determine what the scope Operations and what further actions may be appropriate.
of this was and PRA personnel to A meeting was held with Operations, Engineering 11/28/01 mechanistic 7detaillssof thee discuss the significance and appropriate actions. The 1300 The consensus wwas issue were well understood and developed by all present.
that it required further that this item represented a real possibility, and focusing primarily on attention. Various possible actions were discussed, as well as modifications enhancing Operator awareness of the system design, eliminate it.
or procedural changes that may be desirable to the meeting, and it was agreed The subject of Operability was discussed during no equipment degradation, that there was no operability concern because Regardless, the level of failure, or non-conformance had been identified.
was felt' ustified.
concern was great enough that further prompt action 45
RCE 01-069 Rev. I i Increased CDF in AFW PRA Model Due to Procedural
-; jltated to Loss of Instrument Air 7-. 4
" F1" DESCRIPTION DATEITIME with Engineering about this potential 11/28/01 The Operations manager had discussions CDF risk resulting from an event Late afternoon concern regarding significantly increased the subsequent EOP actions, where instrument air was lost and during which could cause one or more AFW operators may take inappropriate action unmspto fail.
inspectors on the concerns of the issue 11/29/01 - AM Operations manager briefed the resident and risk.
and that we were evaluatin the condition operations concluded that use of 11/29/01 Following discussions with the staff SRO, of all watch standers, would be an Late AM temporary information tags and a briefing We also started evaluating important step to reduce the risk of the event.
the safety of the plant and reduce procedure changes that might help improve the risk profile.
11/29/01 PRA briefed the STA and Shift Manager on the issue and discussed potential 10:00 wordin for control board lacards.
with licensing.
11/29/01 PRA discussed potential reportability concerns 11:00 risk impact values.
11/29/01- PRA briefed the RI and provided estimated t
11:30 was written. The CR was brought 11/29/010- CR 01-3595 documenting the increased risk that time, extensive discussion 14:45 to the WCC and screened by an SRO. At had already occurred, and extensive regarding whether an OD was required My discussions with engineering and discussion on operability had occurred.
not an equipment problem, no others focused on the fact that there was is in question, that this is a risk equipment is degraded such that operability action to mitigate, and therefore, issue upon which we are relying on operator discussions were not captured in use of the OD was not appropriate. Those either the CR, or the associated screening.
information tags placed 11/29/01 - The oncoming crew was briefed and temporary This briefing summarized P-38A/B.
adjacent to the controls for 1/2P-29 and 1520 The temporary information tags provided the concerns of this potential event. for the AFW pumps are 50 a reminder that the minimum flow requirements for the steam driven ur s.
75 GPM GPM for the motor driven um s and SRO (CR 01-3595) 1553 11/29/01- CR 01-3595 was screened by the WCC on this issue.
11/29/01- - Operations Manager briefed Plant Manager i 1700 via ENS phone.
11/29/01 - Event Notification 38525 made to NRC 1705 the NRC-NRR backup PM concerning 11/30/01 - AM Licensing manager received a call from A return conference call was made with confusion over the event notification.
engineorincto address NRR uestions.
46
RCE 01-069 Rev. I I Increased CDF in AFW PRA Model Due to Procedural InadeauaciesRelated to Lbss of InstrumentAir DESCRIPTION DATE / TIME.
Operations Manager 11/30/01 -AM Friday morning, after discussing this with the residents, of the AFW system, we concluded that to properly document the operability discussionswe had should initiate an operability determination to ensure the documented.
the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> regarding operability were properly Engineering was requested to start on the OD. 'The Shift Manager was an OD on the issue was being performing it and that it was informed that expected to be, completed mid to late afternoon.
supervisor to Operations Manager met with Sr. Resident, Resident, and their their concerns regarding 11/30/01 discuss situation. At that point NRC brought forward Noon prior to Thursday whether AFW was operable in the condition that existed called and whether it was currently operable. The hadManager Plant a discussion NRC Region III along with the Operations Manager and afternoon regarding operability of the system... to a loss of Ran a simulator scenario to get information on plant response 11/30/01 air pressure.
offsite power coincident with a rapid loss of instrument 1400 11/30 and 12/1.
NOTE: Additional simulator'scenarios were run on and EOP-0. 1 to 11/30/01 Temporary procedure changes were completed to EOP-0 the temp info cards.
1645 reflect the guidance provided earlier to operators on team would 11/30/01 Plant Manager informed that a five-man incident investigation
-1700 arrive on 12/3.
to the NRC to clarify the 11/30/01 A supplement to the Event Notification was provided in the original 1746 discussion of the potential for an AFW failure as described event notification 38525 operability of the AFW 11/30/01 The OD was approved. This OD evaluated the current measures already taken
-1830 system and included a discussion of the compensatory to assure compliance with our licensing basis.
12/1/01 -0930 Staff meeting to prepare for NRC inspection team.
to 1200 The discussion of 12/1/01 - 1515 Revision 1 to the Operability Determination was approved.
the AFW pump motor duty cycle was revised.
12/3/01 - 0830 CR 01-3595 screened as requiring an ACE.
NRC entrance meeting.
12/3/01 - 1000 Inspection Team meeting to prepare presentation for to 1200 a RCE.
12/3/01 - 1200 SVP and Plant Manager agree that CR 01-3595 requires 12/3/01 - 1400 NRC Inspection Team has entrance meeting.
12/4/01 HEP expert onsite 12/4/01 - 0700 Initial RCE Team meeting held.
12/4/01 - 1200 Plant Manger approves RCE Charter.
with MDAFW pump 12/4/01 - 1620 CR 01-3633 initiated on Appendix R concerns associated and LOOP and loss of IA and coincident fire. (CR 01-3633) to an Appendix R fire 12/5/01 - 1545 CR 01-3648 initiated on response of MDAFW Pump for auto-start with coincident with a LOOP and loss of IA. Potential existed pump damage. (CR 01-3648) discharge and recirc valves failed closed causing 12M/70I - 090( NRC Inspection Team has technical debrief.
47
RCE 01-069 Rev. I I IncreasedCDF in AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air DESCRIPTION DATE / TIME 12/13/01 - NRC Inspection Team has exit meeting.
14UU 14U If( _____________________________________
12/14/01 Permanent Revision to EOP-0 and EOP-0.1 implemented.
12/20/01 Additional revision made to EOP-0, EOP-0.1, and ECA-0.0 48
RCE 01-069 Rev. I Increased CDFin AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air Attachment C: Why Staircase air scenario due to a Problem: There is an increased CDF during a loss of instrument common mode failure of all AFW pumps.
because of RCS cool Why?: EOP-0.1 contains a step (step 1) to CONTROL feed flow (step 4) to STOP feed flow to a down considerations (RCS overcooling) and another step below the desired setpoint steam generator if an increasing level cannot be maintained I used to CONTROL or STOP (SIG overfill) - these steps do not specify the method to be AFW discharge valves closed flow. (It is postulated that an operator could throttle the are failed closed or fail and with a loss of instrument air when the recirculation valves themselves in a few closed later, the running pumps would dead-head and destroy minutes; a common mode failure.)
to direct operators to take the Problem: EOP-0.1 contains insufficient information flow to S/Gs under a correct actions for controlling AFW flow or stopping AFW loss of instrument air scenario.
for directing operator Whyl?: Reliance had previously been placed on AOP-5B it was just recently response to a loss of instrument air scenario; however, earlier in would be required recognized by the PRA group that action by operators level without the the scenario while still in EOP-0.1 (e.g., controlling SfG availability of the AFW recirculation valves).
actions for AFW flow Probleml: The need for specific operator response in EOP-0.1 was not control due to a loss of instrument air scenario while previously identified.
not evaluate the Whyl-l?: The original validation of EOP-0.1 did analysis.
interaction between design, procedures and human error/timeline (Human This analytical method was not available at that time.
Error/Timeline Analysis Not Available) actions to Whyl-2?: The original PRA model did not model operator it was assumed that control AFW flow in the system fault trees because overfill) would be there was a long time available and the function (SIG was not identified alarmed (assumption 13). The flaw in this assumption trees were based primarily during the PRA model review because the fault only operator actions on functions described in design documents. Also, selection of the evaluation taken to mitigate a failure were evaluated. The over other FMEA method using fault trees focused on design functions function approach methods was based on an assumption that the design review uses a was more conservative. The current PRA model with potential human methodology that integrates system performance 49
Increased CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air actions to obtain a spectrum of planit responses. (PRA Model based on system functions)/(Only mitigating actions were evaluated)
Whyl-3?: The operator action to control AFW flow had not been identified as a human interaction with a human error probability assigned to it. (Human Error/Timeline Analysis Not Available)
Why2?: Previous evaluations of the effects of the AFW recirculation valves failing closed on loss of IA concluded that the AFW pumps would not be damaged because forward flow was always available. Closure of a single discharge valve due to component failure concurrent with the AFW recirculation valve failing closed was evaluated and considered to be outside the design and licensing basis. (This used NUREG-0800 assumptions and PBNP was not committed to that NUREG.) Closure of all the discharge valves due to operator action was riot considered.
Problem2: Closure of the AFW discharge valves due to operator action was not previously considered as a possible failure mechanism.
Why2-1?: The consideration of human actions in failure modes and effects analyses has occurred primarily only in the PRA area and the integrated method of evaluating FMEA, human error probabilities, and timeline studies is a recent development. (Human Error/Timeline Analysis Not Available)
Why 2-2?: Insight was needed to understand that the actual operator response to a "CONTROL or STOP feed flow" command under a loss of instrument air scenario would be closure of the discharge valves instead of stopping the AFW pumps.
Problem: The expected operator response to the "CONTROL or STOP feed flow" command under a loss of instrument air scenario was not clear.
Why?: Training materials did not contain specific information on operator actions for controlling steam generator level (and AFW flow) under a loss of instrument air condition.
Problem: Training materials did not specify the actions required for successful control of AFW flow under loss of instrument air conditions.
Why?: The importance of the AFW control evolution was not previously recognized. (Human Error/Timeline Analysis Not Available) 50
RCE 01-069 Rei I Incrr..,ased CDFin AFW PRA Model Due to Procedural InadequaciesRelated to Loss of InstrumentAir Attachment D: Event & Causal FactorChart I KEY UNVERIFIED CTI PPROPRIAT Eýý>
CONTRIBUTING n CAUSAL FACTOR CS..cO.O I... , o.m "n 51
RCE 01-069 Re I In. .sed CDF in AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air KEY INAPPROPRIATE UNVERME ( actos 4Ecjlj CTIO EVENT odto CONTRIBUTING ROOT ( CAUSAL ivsJ FACTOR CAS ,CONDITION 890~o~~
52
0 In. .tsed CDF in AFW PRA Model Due to Procedural RCE 01-069 Rt I InadequaciesRelated to Loss of Instrument Air KEY INAPPflOPStATE CTION 53
4 RCE 01-069 Re InfL. .asedCDF in AFW PRA Model Due to Procedural I
InadequaciesRelated to Loss of Instrument Air 4/26/85 PBNP responded to revised NRC AFW TER KEY UNVERIFIED, EVNI=NAPPROPRIATE EVENTI ~ CT1CN CAUSAL COIIvSsII-il CAUE COt4OIflONJ' stiII 54
-. 4 InL. ..sed CDF in AFW PRA Model Due to Procedural RCE 01-069 Re.
InadequaciesRelated to Loss of InstrumentAir KEY UNVERIFIED I L21.1J ION ondifflon CI EVENT
'-N (~~'\ CONTIBUTIjrNG CAUSAL Sinvests.J FACTOR AU CONDITION.,, abo 55
Ltd."
RCE 01-069 Re, I lnc, sed CDF in AFW PRA Model Due to Procedural Inadequacies Related to Loss of InstrumentAir KEY ACTIO INAPPROPnIATE EVENT L.............
S~........-,, allon CONTAIEUTINO CAUSAL C( fFACTOR1:
ROO_
AU '-.,.ONDTION.."
Discrepancy 56
h,. ased CDF in AFW PRA Model Due to Procedural RCE 01-069 R, I InadequaciesRelated to Loss of Instrument Air KEY IUNVERIFIED EVENT LJ 48e.
o'Cnd~iofl-INAPPROPRIATE MTO ROO (CAUSAL CTOR]'k FAIv~f.
CAS .SooON.
I a-l "Theslgn review did" not identify concern with FC recirc vIvs, 57
4 InL .sed CDF in AFW PRA Model Due to Procedural RCE 01-069 Re I InadequaciesRelated to Loss of Instrument Air KEY UNVERIFIED I Factors/
1 EVENT ROOT ~CAUSAL HvsI CAUE '.CoOITO a FCTO 219189 NPERS evaluation of SOER 88-01 Issued 58
L L.0 JIlL 'ed CDF in AFW PRA Model Due to Procedural RCE 01-069 Rei InadequaciesRelated to Loss of Instrument Air KEY t *ý81
-NAPPROP MlATE UNVE RIFIED V NT I FactortlTI EVENT CTIOlo
,'iJNVEONED / BUTING ROOT CAUSE CASAO
.. COND, T.s ~ FACTOR/
"AFWdlsch AOVs' FO could overfeed S/Gs 59
RCE 01-069 Rev I Inc, oed CDF in AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air KEY F 5a INAIPATOPR?>ATE UNVERIFIED tos <, CF tEVENT 1 VN 1
~CTIO ROO ( CAUSAL CIrwesiIO CAS .'.COND IO.N,. antion~
VRR-28 recirc linedescribes function 60
RCE 01-069 Rei I Inc. .;ed CDF in AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air KEY CO UNV ERIFIEDi IEI EVENT CONTRBUTIN
...~~.o,Co*..
CAUSAL FACT1O 61
Inc, . ,sed CDF in AFW PRA Model Due to Procedural RCE 01-069 Re I InadequaciesRelated to Loss of InstrumentAir KEY A
UNVEN cI r-~--iINAPPROPRlIATE Fu.e. CTIO FACTOR Based on NUREG- ( NUREG-0800 not ROCA., EIr%
S L 1"69 fo CONCONTNUfING 0800 assumptions } part of PBNP CLB CAUSE TAION.
JCD Ho Affects -1995 of excessive AFW flow put into EOPs 62
9 RCE 01-069 Rei I JIn(. .sed CDF in AFW PRA Model Due to Procedural InadequaciesRelated to Loss of Instrument Air KEY EVEENTT (3Dtos~
.1JNVR!P!~.,for~ CONTWBIUTING.
ROT (CAUSAL ( ......
- " FACTOR CAS ,'.CONDITION. katton 63
-4 In.. .sed CDF in AFW PRA Model Due to Procedural RCE 01-069 Re. I InadequaciesRelated to Loss of Instrument Air KEY UNVERIFIED EVENT NAPPROPRIAT EVENT CTIO
,.............. <Eýa>
CONTRIBUTING CAUSAL I FACTOR CAU.E..co.. .ON_. ~InveS.I.J 64
Int. .sed CDF in AFW PRA Model Due to Procedural RCE 01-069 Re. I InadequaciesRelated to Loss of InstrumentAir KEY
.............. r uu .3a UNVERIFIED EVENT I J EVENT
'~onfditin PPactaMAT n
( CAUSAL QOO.- FACT I
-AUS ONDITION 65
itL sed CDF in AFW PRA Model Due to Procedural RCE 01-069 Re I InadequaciesRelated to Loss of Instrument Air KEY UVr IFE 'ua INAPPSOPRIATE EETonditlon <E AC-TION
,NVEI~l~P~~for\ CONTRIBUTING CAUSAL IFACTOR CAUS CONDI.rON / aflo 6/01 Late June or Early PRA group revising July'01 PRA group AFW portion of PRA identifies concern with model AOP-5B 66
0 RCE 01-069 Re, I Inc. ,sed CDF in AFW PRA Model Due to Procedural InadequaciesRelated to Loss of InstrumentAir KEY UNVERIFIED I m ~ NPPO~A EVENT CTIO Zau,:a,:)
CONTRIBUTING OCAUSAL FACTOR
\'.AUSE. .COnO
.ON.
eanveS l-11/26/01 Risk evaluation performed on AFW recirculation valves 67
-I Incr, d CDF in AFW PRA Model Due to Procedural RCE 01-069 Rev. I InadequaciesRelated to Loss of Instrument Air KEY SUNVERIFIED VFW INAPPROPRIATE EVENT L Ca CTION CAUSAL I CAUS ... ~CO.N2,r.oI 68
INTERNAL Cammrtredto Nuclear Exceence CORRESPONDENCE NPM 2002-0495 To: CARB Members From: Richard Flessner Date: September 16, 2002
Subject:
Addendum to RCE 01-069 Rev.I/ACE000314 Copy To: S. J. Nikolai S. A. Pfaff L. J. Peterson File The attached addendum to RCE 01-069 Rev.I/ACE000314 is being submitted for CARB review and approval. This addendum is being created to provide a more complete documentation record of items related to RCE 01-069 Rev. 1. The focus of the addendum is primarily on actions taken after the RCE was completed and accepted by CARB. A revision to the RCE is not deemed necessary because the basic conclusions and resulting recommended actions have not changed.
Additional discretionary actions have been implemented by NMC and are being included in the addendum for a more complete record.
Attachment P,
Addendum to RCE 01-069 Rev.1/ACE000314 This addendum to RCE 01-069 Rev.1 (ACE000314) covers the following items:
- 2. Comments on Independent Review of RCE Report
- 3. Addition of the Open Safety Function to the AFW recirculation valves
- 4. Creation of action items to document corrective actions described in RCE report
- 5. Expansion of Extent of Condition Review
- 6. Effectiveness Review Reason for Addendum- This addendum is being created to provide a more complete documentation record of items related to RCE 01-069 Rev. 1. The focus of the addendum is primarily on actions taken after the RCE was completed and accepted by CARB. A revision to the RCE is not deemed necessary because the basic conclusions and resulting recommended actions have not changed. Additional discretionary actions have been implemented by NMC and are being included in the addendum for a more complete record.
- 1. Inaccuracy in RCE report regarding IST program testing On page 23 of RCE 01-069, Rev. 1, a statement is made regarding the deletion of open testing of the AFW recirculation valves from the IST program as a result of the evaluation made for CR 97-3363. Additional review has determined that testing of the AFW recirculation valves was not deleted, and that time testing data exists for all 4 AFW recirculation valves during the period 1993 to 2002.
- 2. Comments on Independent Review of RCE Report The independent review of the AFW RCE (CAP002612/CA004074) contained the following final conclusion:
"The following final conclusion is based upon the scope of the investigation as prescribed by the management team in the investigation charter. The RCE represents a high quality, detailed, integrated investigation into the problem statement described in the Team Charter. The report is well constructed and well written and allows a non-involved reader to understand the event and the investigation performed. The root cause is supported by the facts, evidence and failure modes identification. The corrective actions are appropriate for the scope of the investigation and will ensure higher quality EOP documents in the future. Questions regarding the adequacy of the overall scope of the investigation are contained in the main body of the report."
Specific issues discussed in the review are:
" Charter/scope of investigation does not investigate why the design allowed the recirculation valves to fail-closed on loss of instrument air and how this condition went uncorrected until discovered by the PRA review.
Comment: The fail-closedposition was known and understood in the design and did NOT go uncorrecteduntil discovered by the PRA review. What was not known was the timing of operatoractions and the need for specific guidance in the EOPs. The problem was determined to be a proceduralissue by PBNP and the NRC; hence the investigation scope was appropriate.
" No corrective actions exist to ensure that similar components do not have the same failure mode.
Comment: Since there was not a problem with the failure mode of the valve, there was no need to evaluate similarcomponents. All operatoractions associated with a loss of instrument air condition were evaluated and determined to be appropriate.
" Root cause may be too narrowly focused.
Comment: The RCE evaluated the mismatch between plant design and plant procedures It was determined that the revised procedures could adequateý, support the plant design. The cited violation is for a procedural problem and not a design issue: hence, thefocus was appropriate.
" Barrier analysis might also be used (in addition to E&CF charting) on the EOP development and validation process.
Comment: This would be an enhancement. Since the EOPs have been through 3 major revisions by WOG and the current processes for verification and validation are different (and enhanced by corrective actions in the RCE), it was felt that no value would be added by an additional barrier analysis.
" Report does not discuss use of single failure analysis in deriving EOPs.
Comment: This comment was based on the misperception that the fail-closed mode of the recirculationvalves was not correct. Single failure analysis would be in addition to the designed failure mode of the valve and would not have been applicable.
" RCE did not address timeliness or effectiveness of CA program in bringing issue to management's attention (initial CR 01-2278 written 7/6/01).
Comment: This issue was discussed between the RCE investigator, his Manager and the PRA Group Lead during the RCE evaluation and determined to be appropriate based on the complexity of the issue, the involvement of operations,and risk associatedwith the issue at that time; therefore, no concern was identified in thefinal RCE. A statement of there being no problem was not added.
" Was deletion of testing the recirculation valves (in the open direction) from the IST program a dropped or missed commitment?
Comment: Evaluation of this item has determined that time testing of the AFW recirculationvalves in the open direction is occurringand has not been deleted.
" RCE does not discuss how PBNP specific design differences were identified through the original EOP development process.
Comment: The report describes the EOP verification process in general terms and the results obtained. The verification was via an approved procedure and checklist. There were more than 2500 discrepancy sheets identified, which is ample evidence that specific plant differences were considered.
" Is it a safety function for the recirculation valves to open?
Comment: The report clearly describes the plant's licensed position that there was no required OPEN safety function for the recirculation valves. The NMC decision to add the OPEN safety function was based on improving equipment reliabilityand reducing CDF risk
" Report does not discuss any findings regarding design configuration control differences.
Comment: The report identifies that there were inconsistencies between the FSAR, IST and DBD documents and initiated a corrective action to review the current versions for consistency. This was treatedas a broke-fix issue since it was not a significant contributing cause to the event. The evaluator's perception of a design problem gave this issue more importance than warranted.
There is no discussion on how the PBNP design compares to other similar plants AFW design.
Comment- A review of other plants AFW designs was performed and the PBNP design was found to be fairly unique; since there was no design deficiency, the issue was not discussed in the RCE report.
" The design change for adding pneumatic back-up supply to the recirculation valves is not identified as a corrective action in the RCE Comment: This corrective action was added to Revision I of the RCE.
- 3. Addition of the Open Safety Function to the AFW recirculation valves During ongoing reviews of the AFW recirculation issue, NMC determined that there was increased nuclear safety benefit (improved reliability and reduced CDF risk) in the addition of an open safety function to the AFW recirculation valves beyond that credited by the pneumatic back-up supply modifications already installed.
Therefore, modification MR 02-029 was initiated to add the open safety function to the AFW recirculation valves.
This MR included removal of the internals of the AF- 117 check valve to eliminate a common mode failure. The modification was accepted on 9/12102.
- 4. Creation of action items to document corrective actions described in RCE report RCE 01-069, Rev. I identifies the corrective actions already taken and those being implemented in section VIII of the report, beginning on page 37. T-track references had been provided for the actions being implemented, but not for all of the actions already completed. Subsequently, t-track records have been created to adequately document the completed actions discussed in the report. The following action items have been created:
"* Interim Corrective Action #1 - CA026222
"* Corrective Action #17 - CA026223
"* Corrective Action #18 - CA026224
"* Corrective Action #19 - CA026225 Other t-track items related to this event are:
0 CA002592 - This item documents the review of the condition from a short-term Maintenance Rule risk monitoring perspective.
- CA002593 - This item documented the OD review of the condition.
- CA002594 -This item tracked issuance of the LER for this event.
o OTH003541 - This item tracked presentation of the completed RCE to CARB.
- CA003983 - This item brought closure documentation back for CARB review once CA00369 1, CA003692 and CA003693 were completed.
- OTH004389 - This item tracked revision of the RCE to reflect information gained during preparations for the NRC regulatory conference.
- OD Part I Rev 2 - This document is attached to the parent CAP001415 and documents the operability determination of the original condition.
- OTH0045 10- This item tracks the correction of problems identified with some HEPs from the review performed under CA004388 0 CAP01201 I/CE010138 (KNPP) - These items document KNPP's review of the industry OE notification issued for this event.
- 5. Expansion of Extent of Condition Review The EOP weakness regarding controlling AFW flow was found during the PRA model update for the AFW system.
The PRA model update involved a simultaneous review of plant design, procedures, failure modes and timing of operator actions. However, the update process is not specifically designed to identify procedural errors. Therefore, an alternate approach was developed that combined the elements of the effects of a loss of support component function, the procedures that deal with resolving this function, and the timing of required actions. CAP029344 has been initiated to expand the extent of condition review for the AFW Red Finding using this alternate approach to provide an additional level of assurance that similar issues do not exist in other emergency procedures.
- 6. Effectiveness Review T-track action item CA003983 was created following the CARB Meeting on 3/5/02 to bring back closure documentation for review at a CARB Meeting once CATPRs 1 and 2 (CA003691 and CA003962), and corrective action #1 (CA003693) were completed. CA003693 is associated with the overall PRA update project, which now has an approved action plan that extends to the end of 2004. It is recommended that the scope of CA003983 be modified to be an effectiveness review of the completed CATPRs as normally performed on RCEs
Page 1 of 3 Nmclear,.Management Company STATE CHANGE HISTORY
- a L Conduct Work Review & Approved Quality Check Assign Work Assign Work Complete Approval Initiate 9,13/2002 913/2002 9/3/2002 S> 9/3/2002 6:24"39 PM 6.25.37 PM 6 19 55 PM 6 22 15 PM Owner Owner Owner by RICHARD Owner by RICHARD RICHARD by RICHARD RICHARD by RICHARD RICHARD FLESSNER PBNP CAP FLESSNER SWi FLESSNER FLESSNER FLESSNER Admin FLESSNER FLESSNER I-SECTION 1 Activity Request Id: CA026222 Corrective Action Submit Date: 913/2002 6:19:55 PM Activity Type:
Site/Unit: Point Beach Common Activity Requested: Intenm CA#1: Revise EOP-0, EOP-0.1 and ECA-O.0 to address AFW control under loss of instrument air conditions.
0 CATPR: N Initiator:
- MASTERLARK, JAMES EXC Engineering Initiator Department: EPN Engineering Responsible Group Code:
Processes Continuous Programs Nuclear Safety Analysis PB Improvement PB D RICHARD FLESSNER Responsible Department: Engineering Activity Supervisor:
Activity Performer: RICHARD FLESSNER SECTION 2 Priority: 3 Due Date: 9/3/2002 Mode Change Restraint: (None) Management Exception From Pl?: N 0 QA/Nuclear Oversight?: N 0 Licensing Review?: N NRC Commitment?: N 0 NRC Commitment Date:
SECTION 3 Activity Completed: 9/3/2002 6:24.39 PM - RICHARD FLESSNER The following documentation was reviewed and demonstrates completion of this item as stated in the RCE:
EOP-0 Revisions
- TCN 2001-0871 was approved on 11/30/01 for Rev. 35 of Unit 1 EOP-0 to add AFW minimum flow requirements to the Fold Out Page The TCN was incorporated into a permanent change issued as Rev. 36 on 12/14/01.
- TCN 2001-0872 was approved on 11/30/01 for Rev. 36 of Unit 2 EOP-0 to add AFW minimum flow requirements to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 37 on 12/14/01.
- TCN 2001-0915 was approved on 12/20/01 for Rev. 36 of Unit 1 EOP-0 to add reference to the IA HEADER LOW PRESSURE annunciator for AFW minimum flow requirements to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 37 on 1/10/02.
- TCN 2001-0914 was approved on 12/20/01 for Rev. 37 of Unit 2 EOP-0 to add reference to
Page 2 of 3 Nuclear Management Company the IA HEADER LOW PRESSURE annunciator for AFW minimum flow requirements to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 38 on 1/10/02.
- TCN 2001-0873 was approved on 11/30/01 for Rev. 24 of Unit 1 EOP-0.1 to add AFW minimum flow requirements to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 25 on 12/14/01.
- TCN 2001-0874 was approved on 11/30/01 for Rev. 23 of Unit 2 EOP-0.1 to add AFW minimum flow requirements to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 24 on 12/14/01.
- TCN 2001-0916 was approved on 12/20/01 for Rev. 25 of Unit 1 EOP-0.1 to add reference to the IA HEADER LOW PRESSURE annunciator for AFW minimum flow requirements to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 26 on 1/10102.
- TCN 2001-0913 was approved on 12/20/01 for Rev. 24 of Unit 2 EOP-0.1 to add reference to the IA HEADER LOW PRESSURE annunciator for AFW minimum flow requirements to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 25 on 1/10/02.
ECA-0.0
- TCN 2001-0917 was approved on 12/20/01 for Rev. 29 of Unit 1 ECA-0.0 to add AFW minimum flow requirements and reference to the IA HEADER LOW PRESSURE annunciator to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 30 on 1110/02.
- TCN 2001-0912 was approved on 12/20/01 for Rev. 30 of Unit 2 ECA-0.0 to add AFW minimum flow requirements and reference to the IA HEADER LOW PRESSURE annunciator to the Fold Out Page. The TCN was incorporated into a permanent change issued as Rev. 31 on 1/10/02.
SECTION 4 (None) Licensing Supervisor: (None)
QA Supervisor:
SECTION 5
" Project: CAP Activities &
Actions Quality Check 0 Activeflnactive: Active
" State:
PBNP CAP Admin AR Type: Parent
" Owner:
RICHARD FLESSNER Assigned Date: 9/3/2002
" Submitter:
9/3/2002 6:25"37 PM Q Last Modifier: RICHARD FLESSNER
" Last Modified Date:
0 Last State Changer: RICHARD FLESSNER
" Last State Change Date: 91312002 6:25.37 PM 0 Close Date:
0 One Line
Description:
Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW NUTRK ID: CR 01-3595 Child Number: 0
References:
CR 01-2278 RCE 01-069 GOOD CATCH Update: This CA is being issued to document a completed corrective action.
Import Memo Field:
Nuclear Management Company Page 3 of 3 OLDACTION_NUM:
Cartridge and Frame:
ATTACHMENTS AND PARENT/CHILD LINKS El Linked to ACE000314" Probabilistic Risk Assessment PRA For Auxiliary Feedwater System AFW
/
- Subtask from CAP001415" Probabilistic Risk Assessment PRA For Auxiliary Feedw.ateLSystem AFW
0 Nuclear Pov er Business Unit / t, II TEMPORARY CHANGE REVIEW AND APPROVAL "Note. Refer to .NP 1.2 3, Temporan, ProcedureChanges,for requirements Page 1 of I - INITLATION EOP-0 Current Rev 35 Unit PB. Temp Change No g n-g 7 Doc Number Documcnt Title REACTOR TRIP OR SAFETY INJECTION Existing Effective Temporary Changes Brief Descr.ption ADDED FOP ITEM TO ADDRESS AFW MILNLMUMI FLOW and Ln.luda. ,,.h the package)
,Identify spccific changes on Form PBF-C026c. Document Re,.iew and Apr."o'al Contiruat:on,
[ Initiate PBF-0026h and include with the change.
Other documents required to be effective concurrently with the temporary change" NONE Changes prc-screcned according to NIP 10 3.1? [ NO l YES (If Yes. ist re:-.-=d M-1, asP*fF-2 c*, *:X-,,-
f 03 .
Screening completed according to NP 10.3.1? [] NA E YES Safetv Evaluation Required? CO NO [] YES Wves. are s,==uave oceedr.a, or .
s.-.!1d$ _a,,W be-!Icb.er.Ibt Determine if the change constitutes a Change Of Intent to the procedure by evaluating the folloN ing questions.
imp!emenriting)
(If Any ans'.ers are YFS, a revision maý be pro:.er.sd or final reiec s and approvals shall be obtained before Will the proposed change: YES NO
- 1. Require a change to, affect or invalidate a requirement, commitment, evaluation or dcscr-iption in the Current Licensing Basis (as defined in NP 10 3 !)?
- 2. Cause an increase in magnitude, significance or impact such that it should be processed az a revision?
- 3. Delete or modify a prerequisite, initial condition, preca-ation, limitation or other steps that El Z could have safety significance or affect the procedure's margin of safety?
- 4. Delete QC hold points, Independent Verification or Concurrent Check steps without the u related step(s) that require the performance also being deleted?
- 5. Change Tech Spec ot other regulatory acceptance criteria other than for re-baselining LI purposes?
- 6. Require a change to the procedure Purpose or change the procedure classification? [] ,
Initiated By (print-ign) h* ,, ,",.*,../ . < ' Date /."/!
II INITIAL APPROVAL This change is correct and complete, can be performed as written, and does not adv'ers Y'2 ect pers;el or nuclear safety, or Plant operating conditions7 Group Supervisor (printlsign) i,- /, .,( C.t-.- I 7..-' . , -Z7 e /e' <"
(Cannot be the 146tator0 This change does not adversehl affect Plant operating conditions (Sa.ety Re13eed procedures only)
SeniorPRcactorOpcrator(pri,*:sip) ,__.K r .rkevs / i--e -_ ,'., Date ft!heoL Lt (Cannot be the Initiator ot Grou'pSulfernsor)
HII - PROCEDURE OWNER REVIEW El One-time Use El Expiration Date, Event or Condition: SPermancnt required withdin 14 days of initial appropal)
EL 1] Hold change until procedure completed (final QR/MSS Review NOT Required(A.Admir :'SR only) /
review and approval still QR Review Reýc~d. Re'iew Requtred :
ProcedureO,,ner(print/sign) 1Y I z-' Date 36 6 l"ir Cha-re and suporni-,* reoulret~ents correcly co.-'rleted ard vrocessed" IV - FINAL REVIEW AND APPROV'AL (Mu.dt 1w crmpletcd Mithin 14 d,, s ofirdtisl appro-al) (The Initiator, QR and ApproIl Authont. slhall be independent from each other) 5, . 1--7LC_., *Da Ii o j/c't SSt rr.At sign) J*/rl performed dt:'ina-tion.*nade as to htl-ct aa :!ela Ind"fi-,es 50 19.'1148 ap*',ab*ibl'% *asesscd. An:. ncccsrar. s.-reenings, calu0t113 cor-is-J:sciplirar, rvicv required, and ifrequired, perfermed
/
MSNS MeetingNo I/, -,' /
Approval Authority Cprr.L'sign) h _ Date V- REVISION INFORMATION FOR PE -sNEST CHANGS" K .-
J.Ie pr~'/
1 7
Post r%niitg Reiw(pr~ i~nt'u' s.ctya --
Intj ,.-.,,,..; ,cn p o ,-. . o.- ,.i Z'Z asc " C- , " ot, :r ch --n. c _-. e ,< -., - ",. . D ' 1 4 7r,' p
,__Effct___ c Date _
lncorporatcd into Rcv~sion Number _
REC'D DEC 1 7 2001 %1`1:3 Pl;l'-ot.K26 e.
Re\"nlonI I/ II M, -j-,I
Point Beach Nuclear Plant
'4 DOCUMENT REVIEW AND APPROVAL CONTINUATION Paze 2c of -
Doc Number EOP-0 Rcvision 35 Uprt Titlc REACTOR TRIP OR SAFETY INJECTION Tcmporan Changc Number Lo*pt - og71 Description of Changes:
Stcp Change/Reason CHANGE: Added AFW minimum flow requirements for the AFW pumps REASON: To prevcnrt damage to the AFW pumps on a loss of instnumcnt air duc to the AFW pump mini-rccirc valve failing shut with minimum flow through the pump is less than required to cool the FOP pump 4-I-
I I
_________________________________I i
I-I.
IOther Commen~ts ri
- ,.' fo- muit.rI: o,.rTncS oridnt2.z.+/-I ,nf.r, er : ict b-.jf.f:,al 1o rI .
t
- NoiI Re,'r~ ig utep Numberi is nc" , !oic I
P~l'l.O-0C( .:
i'%.x:Jone 0- '.Sol1
I/Y 4,:' Point Beach Nuclear Plant TEMPORARY CHANGE AFFECTED NLANUAL LOCATION Page ._. of 7 Procedure Number EOP-0 Revision 35 Unit PBI Title REACTOR TRIP OR SAFETY INJECTION Temporary Change Number ,, - S 7 I - IMMEDIATELY AFTER INITIAL APPROVAL ON PBF-0026e (Non-Lbter. changes)
(after Final Approval if change of intent involh ed)
Date This procedure change has been processed as followas: (Manual/Location) Performed E] Copy included in work package for field implementation. (WO No. )
Copy filed in Control Room temp change binder (Operations only). ii7IOiI S Original change package provided to C(Z6 to obtain Procedure Ow.ner Revie (eg. Owner review may be coord.naled by In-Group OA II Procedure Writer. Procedure Supervisor. cW) .
LI Performed By (print and sign) * ,
- tu.\
\,,j i ,," !- Date jo II - PROCEDURE OWNER REVIEW ON PBF-0026e (may be performed by OA IL Procedtze Writer, etc.)
I Date This procedure change has been processed as follows: (Manual/Location) Performed Copy sent to Document Control Distribution Lead for Master File. I [ -3
- o (Not re*qired for one-time use change)
El Copy filed in Group satellite file. tNot required for one-time use changes) _
jZJ Copy filed in Group one-time use file.
[ Original Temp Change provided to !.o. to obtain Final Approvals [ "
I g.... _y :-.t-d
.. by, In-Group OA II Procedure Writer, Procedure Su'erasor. etz.) ,___i__
1, ,. ---, - -1 Performed By(printandsign) Z .Z ,'-
- / Date.,t. L/
I PDF-0026h Revi*ion5 00613,01 Pef¢¢t.:ci NP I : 3
Point Beach Nuclear Plant SCR cOD1t0ly Vt.if., SCR r.anintr on alI pagvs 10 CFR 50.59172.48 SCREENING (NEW RULE) Page 1
""of Proposed Activity: Un;t 1 EOP Rev. 35. Unit 2 EOP Rev. 36. Unit I EOP-0.1. Rc', 24. Unit 2 EOP-0 I - Rev 23 Associated Reference(s) #-: CR 01-2278 Action 2 Prepared b%: Bob Wartenberg Date ~'
Name ( Print) izriature Rcvic%%cd bN. Clayton Graves Date:/
Name (Pnnt)
PART 1(50.59/72.48) - DESCRIBE THE PROPOSED ACTIVITY AND SEARCH THE PLANT AND ISFSI LICENSING BASIS (Resource Manual 5.3.1)
NOTE: The "'NMC 10 CFR 50.59 Resource Manual" (Resource .Ianual) and NEl 96-07. Appendix B. Guidelines for 10 CFR 72.48 Implementation should be used for guidance to determine the proper responses for 10 CFR 50.59 and 10 CFR 72.48 scrcenings.
1.1 Describe the proposed activity and the scope of the activity being covered by this screening. (The 10 CFR 50.59 172.48 review of other portions of the proposed acti ity may be documented via the'applicability and pre-screening process requirements in NP 5.1.3.) Appropriate descriptive material may be attached.
A foldout-page item is being added to Units I & 2 procedures EOP-0 and EOP-0. 1. The foldout page item, "AFW Minimum Flow Requirements", shall address minimum flow required by the AFW pumps in the case of a failed closed rndni-recirc valve on any running AFW pumps.
1.2 Search the PBNP Current Licensing Basis (CLB) as follovxs: Final Safety Analysis Report (FSAR), FSAR Change Requests (FCRs) with assigned numbers, the Fire Protection Evaluation Report (FPER). the CLB (Regulatory) Commitment Database.
the Technical Specifications (both Custom and Improved), the Technical Specifications Bases, and the T.chni*a, Requirements Manual. Searc'h the ISFSI licensing basis as follows: VSC-24 Safety Analysis Repcrt. the VSC-24 Certificate of Compliance. the CLB (Regu*!tory) Commitment Database, and the VSC-24 10 CFR 72.212 Site Evaluation Report.
Describe the pertinent design function(s), performance requirements, and methods of evaluation for both the plant and for the "caskIISFSIas appropriate. Identify %%herethe pertinent information is described in the abo- e documents (by document section number and title). (Resource Manual 5 3.1 and NEI 96-07, App B, B 2)
FSAR 10.2. Auxiliary Feedwater System 1.3 Does the proposed activity involve a change to any Custom or Improved Technical Specification (ITS)" Changes to Technical Specifications require a License Amendment Request (Resource Manual Section 5.3.1.2).
Technical Specification Change: El Yes ER No If a Technical Specification change is required. exlplain %%hatthe change should be and vlhy it is required cask 1.4 Does the proposed activity intolvc a change to the terms, conditions or specifications incorporated in any VSC-24 CoC a:iz.tidment request Certificate of Compliance (CoC)? Changes to a VSC-24 cask Certificate of Compliance rcqufire a
[] Yes El No it is r.quired If a storage cask Certificate of Compliance change is required. e\plain i*hat the charge should be and %ýhy RF1 5 I15c R.:. ?5 1sS Rc~i-ion 0 10:14,01
Point Becah Nuclear Plant SCR ,.01 - 0 7 S2 10 CFR 50.59/72.48 SCREENING (NEW RULE) V'-., SCR.-,mr*on at g*s Page 2 10 CFR 50.5-9 SCREENING .........................--------......-------
PART It (50.59) - DETERMINE IF THE CHANGE INVOLVES A DESGN FL.VCTIOV (Resource Manual 5.3.2)
Compare the proposed activity to the relevant CLB descriptions. and an.swer the following questions:
YES NO QUESTION
[ fl Does the proposed activity inmolvc Safety Anailses or structures. s%stems and components (SSCs) ccdated in the Safety Anal) ses?
[3
E] E_ Does the proposed acti,,ity involve SSCs w.hose failure could initiate a transient (e.g, reactor trip. loss of fecdv.atcr.
etc.) or accident. OR R.hose failure could impact SSC(s) credited in die Safe,, Analyses?
[
- Does the proposed activity involvc CLB-described SSCs or procedural controls that performn functions that are required by, or othenvise nectssy*" to comply %%ith,regulations, license conditions, ordcrf or teclmical specifications?
[3 0] Does the activity involve a msethod ofevaluation described in the FSAR?
C] [0 Is the activity a test or experiment? (i e., a non-passive activity '.%hich gathers data)
EO 02 Does the activity exceed or potentially affect a design basishimitfor afissio-,product barrier(DBLFPB)?
(NOTE: If THIS questions is ansincred YES, a 10 CFR 50.59 Evaluation is required.)
If the ans'-.ers to ALL of these questions are NO, mark Part III as not applicable, document the 10 CFR 50.59 screening in the
-nclusion section (Part IV), then proceed directly to Part V - 10 CFR 72.48 Pre-scfeening Questions.
at any of the above questions are marked YES, identify below the specific design function(s), method of evaluatlon(s) or DBLFPl(s) involved.
FSAR 10.2 states each AFW pumil has an AOV controlled recirc line back to the CST to ensurepump minimum flow to dissipate heat. This change ensures the minimum AEW flow requirements will be maintained on any running AFW in the case of a failed shut AFW miri-recirc flow control .valve.
PART HI (50.59) - DETERMLNEV WHETHER THE ACTMTY INVOLVES ADVERSE EFFECTS (Resource Manual 5.3.3)
IfALL the questions in Part H are ans',%ered NO, then Part III is [0 NOT APPLICABLE.
Answer the following questions to determine if the activity has an ach'erse effect on a design function Any YES ans,.er means that a 10 CFR 50 59 Evaluation is required; EXCEPT i'here noted in Part 111.3.
III 1 CHANGES TO THE FACILITY OR PROCEDURES YES NO QUESTION
[ S[ affect the designfunction of an SSC credited in safety analyses"*
Does the acti,%ity ad%erselN E[ 0 Does the activity adversely affect the methdcA of performing or controlling the design faincwno of an SSC credited in the safety anrul. szs?
if any ans'.er is YES. a 10 CFR 50.59 E'.ahltion is required If both ansvers are NO. describe the basis for the conclusion j (atach additional discussion as necessa')
This change ensures tl-at minimtum recirc flo,%requirements as stated in FSAR 10.2 are not ',iolated.
PBF-151*c RcEismen 0 10,2-I 01 5
.?P.I-
Point Beach Nuclear Plant SCR -OZ - n - Y 10 CFR 50.59172.48 SCREENLNG (NEW RULE) V"'r.. SCR n*.,i.t-.- or. .1;1'PaS "111.2 CHANGES TO A METHOD OF EVALUATION
(!f the ac=i'% tt' does not in o1*e a method of evaluation, these questions are , NOT APPLICABLE)
YES NO QUESTION El [ii Does the acti%it" use a revised or different method of evaluation for performing safetN aalyse.-S than that descnbed in the CLB?
Dl El Does the a:ti%irv use a revised or different method of evaluation for evaluating SSCs credined in safety analyses than that described in the CLB?
If an.,,answer is YES, a 10 CFR 50.59 Evalua.!on is required. If both answers are NO. describe the basis for the conclhusion (attach additional discussion, as neccssan).
I!1 3 TESTS OR E.XPE.UrME.NTS If the acti%ity is not a test or -experiment,the questions in I1L3.a and I11.3.b are ED NOT APPLICABLE.
a Answcr these two questions first YES NO QUESTION El El Is the proposed test or experiment bounded by other tests 6r experiments that are descr;bed in the CLB?
E) 01 Are the SSCs affected by the proposed test or experiment isolated from the facility?
If the answer to BOTH questions in V.3 a is NO, continue to ll.3.b. IfLhe ans.,*er to EITHER question is YES. then describe the basis
- b. Ans;%er these additional questions ONLY for tests or experiments which do NOT meet the criteria given in 111.3 a abo e.
If the answer to either question in III.3.a is YE.S, then these three questions are [] NOT APPLICABLE.
YES NNO QUESTION El rl Does the activity utilize or control an SSC in a manner that is outside the reference bounds of th.- design bases as described in the CLB?
[] [1 Does the activity utilize or control an SSC in a manner that is inconsistent with the analyses or descriptions in the CLB?
El E] Does the activity place the facility in a condition not previously evaluated or that could affect the capatiltt'.
of an SSC to perform its intended functions?
descrnbe the If any answer in III 3 b is YES, a 10 Ct"R 50 59 Evaluation is required. If the answers in111.3 b are ALL NO.
basis for the conclusion (attach additional discussion as necessary).
PBF-It l5c R -10.:. .... IS R,.vL,,on0 i1i'2- Cl01~~1
Point Beach Nuclear Plant SCR ,Oo1- Oik&I 10 CFR 50.59/72.48 SCREENING (NEW RULE) Vef. SCR number on all pases Page 4 Part IV - 10 CFR 50.59 SCREENING CONCLUSION (Resource Marnal 5.3.4).
iock all that apply:
A 10 CFR 50.59 Evaluation is [I required or Z NOT required.
A Point Beach FSAR change is [) required or [0 NOT required. If an FSAR change is required, then initiate an FSAR Change Request (FCR) per NP 5.2.6.
A Regulatory Commuitment (CLB Commitment Database) change is El required or 0 NOT requircd. Ifa Regulatory Commitment Change is required, initiate a commitment change per NP 5.1.7.
is A Technical Specification Bases change is El required or 0 NOT required. If a change to the Technical Specification Bases required. then initiate a Technical Specification Bases change per NP 5.2.15.
A Technical Requirements Manual change is C] required or 0 NOT required. If a change to the Technical Requirements Manual is required, then initiate a Technical Requirements Manual change per NP 5.2.15.
10 CFR 72.48 SCREENING the NOTE: NEI 96-07, Appendiv B, Guidelines for 10 CFR 72.48 Implementation should be used for guidance to determine proper responses for 72.48 screenings.
PART V (72.48) - 10 CFR 72.48 INITIAL SCREENING QUESTIONS Part V determines if a full 10 CFR 72.48 screening is required to be completed (Parts VI and VII) for the proposed activity.
"TS NO QUESTION
[*. Does the proposed activity involve IN ANY MANNER the dry fuel storage cask(s), the cask transfer/transport equipment, any ISFSI facility SSC(s), or any ISFSI facility monitoring as follows: Multi-Assemrbly Sealed Basket (MSB), MSB Transfer Cask (MTC), MTC Lifting Yoke, Ventilated Concrete Cask (VCC), Ventilated Storage Cask (VSC), VSC Transporter (VCST), ISFSI Storage Pad Facility, ISFSI Storage Pad Data/Communication Links, or PPCS/ISFSI Continuous Temperature Monitoring System?
added to support
-, [- [ Does the proposed activity involve IN ANY MANNER SSC(s) installed in the plant specifically cask loading/unloading activities, as follows: Cask Dewatering System (CDW), Cask Reflood System (CRF), or Hydrogen Monitoring System?
El
- Does the proposed activity involve IN ANY MIANNER SSC(s) needed for plant operation which are also used to (SF),
support cask loading/unloading activities, as follos: Spent Fuel Pool (SFP), SFP Cooling and Filtration Primary Auxiliary Building Ventilation System (VNPAB), Dnumming Area Ventilation System tVNDRM),
Vent RE-105 (SFP Low Range Monitor), RE-135 (SFP High Range Monitor), RE-221 (Drumming .Area Gas Monitor), PAB Crane, SFP Platform Bridge, Gas Monitor), RE-325 (Drumming Area Exhaust Low-Range Truck Access Area, or Decon Area?
ents such as El 1 Does the proposed activity involve a change to Point Beach CLB design criteria for external e.
earthquakes, tornadoes, high wvinds, flooding, etc.?
El* ~J Does the activity involve plant heavy load requirements or procedures for areas of the plant used to support cask loading/unloading activities?
or stored?
El
- Does the activity involve any potential for fire or explosion %%herecasks are loaded, unloaded, transported and ansters to the questions in If ANY of the Part V questions are ans-,ered YES, then a full 10 CFR 72.48 screening is required check Parts VI and rl .s not Part VI and Part VH are to be provided. If ALL the questions in Part V are answered NO. Lhen
"-,nlicable. Complete Part VIII to document the conclusion that no 10 CFR 72.48 evaluation is required PBF-1515c Referer.e: NP 5.-1S Revision 0 10f24.'01
Point Beach Nuclear Plant SCR -ý001 -,0 q, 10 CFR 50.59/72.4S SCREENING (NEW RULE) VcnN SCR ru,,br on a1 pa*e PaLe PART VI (72.48) - DETERMJINE IF THE CHANGE INVOLVES A ISFSI LICENSLNG BASIS DESIGN FUNCTION
'ALL die questions in Part V are NO. then Part VI is {*"NOT APPLICABLE)
Compare die proposed activity to the relevant portions of the ISFSI licensing basis and answer the folloiving quiesuors:
YES NO QUESTION E] El Does the proposed activity involve cask/ISFSI Safety Anad) ses or plan,'caskJISFSI structures, systems and components (SSCs) credited in the Safety Anal) ses?
El El Does the proposed activity in%olve plant, cask or ISFSI SSCs that support SSC(s) credited in the Safe,' Analscs?
El El Does the proposed activity inmol%e plant, cask or ISFSI SSCs %,hosefunction is rclid upon for pre%ention of a radioactive release, OR whose failure could impact SSC(s) credited in the Safety Analyses?
El [3 Does the proposed activity inolvc cask/iSFSI described SSCs or procedural controls that perform functions that arc required by, or otherwie necessary to comply %i:lh, regulations, license conditions, CoC conditions, or orders?
El El Does the activity involve a method ofeva!uation described in the ISFSI licensing basis?
E] C1 Is the activity a test or exper.ment? (i.e.. a non-passive activity -uhich gathers data)
El El Does the activity exceed or potentially affect a cask design basishmit ffor afissionproduct barrier(DBLFPB)?
(NOTE: If THIS questions is answered YES, a 10 CFR 72.48 Evaluation is required.)
these questions are NO, mark Parts VII as not applicable. ,ind document the 10 CFR 72. ', screening in the If the answers to ALL section (PartofVIII).
conclusion If any of the above questions are marked YES, idcntify below the specific design function(s), method of evaluation(s) or DBLFPB(s) involved.
PART VII (72.48) - DETERMINE WHETHER THE ACTIVITY INVOLVES ADVERSE EFFECTS (NEI 96-07, Appendix B. Section B.4.2.1)
(If ALL the questions in Part V or Part VI are ans%%cred NO, then Part VII is EL NOT APPLICABLE)
Ansm% er the followving questions to determine if the activity has an adverse effect on a design finction. Any YES arsi er means that a 10 CFR 72.48 Evaluation is required; EXCEPT %%herenoted in Part VII.3.
VII. I Changes to the Facility or Procedures YES NO QUESTION
'l El Does the actnit. ad, ersely affect the designfunction of a plant, cask. orISFSI SSC credited in safety anal) ses?
[E El Does the activity ad ersely affect the method of performing or controlling the designrfancrionof a plant.
cask, or ISFSI SSC crccdied in the safety analyses?
If any answer is YES, a 10 CFR 72 48 Evaluation is required Ifboth answers are NO. describe the basis for Lhe conclusion (attach additional cdscussion, as necessary)
PBF-1515c Revision 0 10'24t01 .*~~ ~ ~~P. S*r¢
Point Beach Nuclear Plant SCR z D O'M1M 10 CFR 50.59/72.48 SCREENING (NEW RULE) Vcriry SCR nu*ber on*-Iges Fagc 6 "VII.2 Changes to a Method of Evaluation (if the activity does not involve a method of eoaluation, these questions arc F1 NOT APPLICABLE.)
YES NO QUESTION El 0l Does the activity use a revised or different method of e aluation for performiig safety anal. ses than that described in a cask SAR?
0l El Does the activitv use a revised or different method of evaluation for evaluating SSCs credited in safety analyses than that described hi a cask SAR?
for the conclusion If any answer is YES, a 10 CFR 72.48 Evaluation is required. If both answers are NO. describe the basis (attach additional discussion, as necessary).
VII.3 Tests or Experiments (If the activity is not a test or experiment, the questions in VII.3.a and 111I.3.b are [: NOT APPLICABLE.)
- a. Answer these two questions first:
YES NO QUESTION cask E- Cl Is the proposed test or experiment bounded by other tests or experiments that are described in the ISFSI licensing basis?
facility?
El 0l Are the SSCs affected by the proposed test or experiment isolated from the cask(s) or ISFSI is YES, then briefly describe If the answer to both questions is NO, continue to VII.3.b. If the answer to FITFHER question the basis.
the criteria given in VII.3.a above.
- b. AnsAwer these additional questions ONLY for tests or experiments which do not meet APPLICABLE:
If the answer to either question in VII.3 a is YES, then these three questions are M- NOT YES NO QUESTION bounds of the design ED El Does the activit, utilize or control an SSC in a manner that is outside the reference bases as described in the ISFSI licensing basis?
is inconsistent with El El Does the activity utilize or control a plant, cask or ISFSI facility SSC in a manner that the analyses or descriptions in the ISFSI licensing basis?
or that could affect El El Does the activity place the cask or ISFSI facility in a condition not previously evaluated the capability of a plant, cask, or ISFSI SSC to perform its intended functions?
are all NO. describe the basis for the If any answer in VII.3.b is YES, a 10 CFR 72.48 Evaluation is required If the answers conclusion (attach additional discussion as necessary).
PBF-1S51c 10r2.01 Refcrct c. NP S.1.S RcvisionO A
SCR -7_01- ,
Point Beach Nuclear Plant _ _i,_
10 CFR 50.59/72.48 SCREENLNG (NEW RULE) Verif: SCR nunm,.r on a1 paj.-s Pa=e 7 PART VIII - DOCUMENT THE CONCLUSION OF THE 10 CFR 72.43 SCREENING Check all that apply:
A 10 CFR 72.48 Evaluation is [] required or OýNOT required. Obtain a screening ntubner and provide the original to Records Management regardless of the conclusion of the 50.59 or 72.48 screening.
A VSC-24 cask Safety Analbsis Report chinge is C] required or a.,NOT required If a VSC-24 cask SAI-'. c:iange is requ;rei. then contact the Point Beach Dry Fuel Storage group supervisor.
A Pegulator" Commitment (CLB Commitment Database) change is 0 required or a.NOT required If a Regulatory Commitment Change is required, initiate a commitment change per NP 5.1.7.
A change to Lte VSC-24 10 CFR 72.212 Site Evaluation Report is El required oro NOT required. If a VSC-24 I0 CFR 72 212 Site Evaluation Report change is required, then contact the Point Beach Dr. Fuel Storage group supervisor.
PBF-1515c R'ac NP 5 1S RcvisionO 10;24O11
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page I of 33 A. PURPOSE
- 1. This procedure provides directions to verify proper response of the automatic protection systems following manual or automatic actuation of a reactor trip or safety injection. assess plant conditions, and direct the operator to the appropriate recovery procedure.
- 2. This procedure is applicable for all plant conditions where RCS hot leg temperature is greater than or equal to 3501F with accumulators in service. and assumes the RHR system is not in service for decay heat removal and all SI system components are available.
B. SYMPTOMS OR ENTRY CONDITIONS
- 1. The following are symptoms that require a reactor trip, if one has not occurred:
REACTOR TRIP SIGNAL I SETPOINT AT Overtemperature Variable AT Overpower Variable RCP Breaker Trip Low Voltage STPT 21.1 RCP Breaker Trip Low Frequency STPT 21.1 RCS Loop Low Flow 93 %
S/G Low-Low Level 25%
S/G Low Level with Flow Mismatch 30% of span PZR Pressure Low 1925 psig PZR Pressure High 2365 psig PZR Level High 80%
NIS Power High Range. High Level 107%
NIS Power Low Range. High Level 20%
NIS Intermediate Range Current equal to 25%
NIS source range 5 X 105 counts/sec Manual Reactor Trip N/A Turbine Trip N/A Safety Inj ection N/A k
POINT BEACH NUCLEAR PLANT EOP-0 UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 2 of 33
- 2. The following are symptoms of a reactor trip:
o Any reactor trip annunciator - LIT o Rapid drop in neutron level indicated by nuclear instrumentation o All rod bottom lights - ON o Reactor trip and bypass breakers - OPEN
- 3. The following are symptoms that require a reactor trip and safety injection, if one has not occurred:
SAFETY INJECTION SIGNAL SETPOINT PZR Low Pressure 1735 psig Steam Line Low Pressure 530 psig Containment High Pressure 5 psig Manual Safety Injection N/A
- 4. The following are symptoms of a reactor trip and safety injection:
- a. Safeguards pumps and associated cooling water pumps- RUNNING
"*SI pumps
"* RER pumps
"* Component cooling water pumps
"* Service water pumps
- b. SI-Spray Active Status Panel white lights - ON
- c. Containment Isolation Panels "A" and "B" white lights - ON
- 5. This procedure is entered from the following procedures if SI actuates:
o EOP-0.2 UNIT 1. NATURAL CIRCULATION COOLDOWN. FOLDOUT o EOP-0.3 UNIT 1. NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITH RVLIS). FOLDOUT o EOP-0.4 UNIT 1, NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITHOUT RVLIS). FOLDOUT
- 6. This procedure is entered from the following procedure when PZR pressure is less than 1735 PSIG:
- EOP-0.1 UNIT 1. REACTOR TRIP RESPONSE. Step 15
- 7. This procedure is entered from the following procedure if PZR level cannot be maintained:
a CSP-I.2 UNIT 1. RESPONSE TO LOW PRESSURIZER LEVEL, Step 7
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 3 of 33
- 8. This procedure is entered from the following procedures if RCS subcooling or PZR level cannot be maintained:
"o EOP-0.1 UNIT 1, REACTOR TRIP RESPONSE. FOLDOUT "o EOP-0.2 UNIT 1. NATURAL CIRCULATION COOLDOWN. FOLDOUT "o EOP-0.3 UNIT 1. NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITH RVLIS). FOLDOUT "oEOP-0.4 UNIT 1. NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITHOUT RVLIS). FOLDOUT
- 9. This procedure is entered from the following procedures when power is restored to a 480 Vac safequards bus prior to placing ECCS components in pull-out:
"o ECA-O.O UNIT 1. LOSS OF ALL AC POWER. Step 16 "o ECA-O.O UNIT 1. LOSS OF ALL AC POWER. Step 26
- 10. This procedure is entered from other plant procedures when a reactor trip or safety injection has occurred.
C. REFERENCES
- 1. Technical Specifications for Point Beach Nuclear Plant
- 2. Final Safety Analysis Report for Point Beach Nuclear Plant
- 3. As-built plant drawings
- 4. Generic Technical Guidelines developed by the Westinghouse Owners Group (WOG). This consists of the following documents:
- a. Low pressure version of the WOG Optimal Recovery Guidelines. Status Trees. and Functional Restoration Guidelines
- b. Background documents for each low pressure version Optimal Recovery Guideline. Status Tree. and Functional Restoration Guideline
- c. WOG Emergency Response Guideline Executive Volume
- d. WOG Emergency Response Guideline Maintenance Program Summary
- 5. Calculation 97-0126. Service Water System LOCA - Recirculation Phase
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 4 of 33 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE Steps 1 through 4 are immediate action steps.
0 Verify Reactor Trip:
- Check reactor trip breakers and Perform the following:
- a. Manually trip reactor.
bypass breakers - OPEN
- b. IF reactor will NOT trip. THEN
"*1-52/RTA perform the following:
"*1-52/RTB
"*1-52/BYA 1) Deenergize rod drive motor
"*1-52/BYB generators by deenergizing IB-01 and 1B-02.
- Check all rod bottom lights - LIT
"* IB52-04B or IA52-02
- Check all rod position indicators "*1B52-05B or IA52-15
- ON BOTTOM
- 2) WHEN the reactor has tripped.
- Check neutron flux - LOWERING THEN close the following breakers:
"*1N-35
"*IN-36 "*1A52-02 for IB-01
"* IB52-04B for 1B-O0
- 3) IF reactor power is greater than or equal to 5% OR intermediate range power is rising. THEN perform the following:
a) Start monitoring Critical Safety Functions per CSP-ST.0 UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to CSP-S.1 UNIT 1.
RESPONSE TO NUCLEAR POWER GENERATION/ATWS.
- 4) As time permits. reenergize stripped MCCs.
- 5) Dispatch operator to locally open reactor trip breakers and bypass breakers in rod control room.
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 5 of 33 Il I ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED Verify Turbine Trip:
- a. Check turbine stop valves - BOTH a. Shutdown turbine as follows:
SHUT:
- 1) Depress turbine trip o SL and SR - SHUT pushbutton.
OR 2) IF turbine will NOT trip. THEN perform the following:
o Annunciator IC03 lEl 4-3.
TURBINE- STOP VALVES TWO CLOSED a) Manually run back turbine.
- LIT b) Stop both EH oil pumps and OR place in pull-out.
o Turbine Valves Closed bistable c) IF turbine still has N0T lights - LIT tripped. THEN shut main steam isolation valves.
" IMS-2018 for S/G A
"* lMS-2017 for S/G B
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 SAFETY RELATED EMERGENCY OPERATING PROCEDURE Revision 36 12/14/2001 Page 6 of 33 REACTOR TRIP OR SAFETY IN'JECTION I ACTION/EXPECTED_*E SPONSE I I I
RESPONSE NOT OBTAINED I Verify Safeguards Buses Energized:
- a. Try to restore power to at least
- a. Check 4160 Vac safeguards buses AT LEAST ONE ENERGIZED one bus:
"o 1A-05. train A 1) Close any supply breaker.
"o 1A-06. train B o IA52-57 for 1A-05 o 1A52-54 for IA-06 o IA52-77 for IA-06
- 2) IF breakers will NOT close.
THEN fast start and load any emergency diesel generator.
- 3) IF power can NOT be restored.
THEN perform the following:
a) Start monitoring Critical Safety Functions for information only per CSP-ST.0 UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to ECA-0.0 UNIT 1, LOSS OF ALL AC POWER.
- b. Check 480 Vac safeguards buses b. Try to restore power to at least AT LEAST ONE ENERGIZED one bus:
"o 1B-03. train A 1) Close any supply breaker.
"o IB-04. train B "o 1A52-58 for 1B-03 "o IB52-16B for 1B-03 "o 1A52-84 for 1B-04 "o IB52-17B for 1B-04
- 2) IF power can NOT be restored.
THEN perform the following:
a) Start monitoring Critical Safety Functions for information only per CSP-ST.0 UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to ECA-O.O UNIT 1.LOSS OF ALL AC POWER.
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 7 of 33 I p
_ _I I ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED I
I I
Check If SI Is Actuated:
0 a. Determine appropriate recovery
- a. Check SI annunciators - ANY LIT actions:
"o 11C04-1B 4-2). MANUAL SAFETY SI is required:
- 1) Check if INJECTION "oContainment pressure OR GREATER THAN 5 PSIG "o (IC04-IB 4-3). CONTAINMENT OR PRESSURE HIGH "o Steam line A pressure - LESS OR THAN 530 PSIG "o (1C04-1B 4-4). PRESSURIZER LOW OR PRESSURE SI OR "o Steam line B pressure " LESS THAN 530 PSIG "o (1C04-1B 4-51. STEAM LINE A OR PRESSURE LOW-LOW OR "o PZR pressure - LESS THAN 1735 PSIG o {lC04-lB 4-6). STEAM LINE B OR PRESSURE LOW-LOW "o PZR level - LESS THAN 10%
OR "oRCS subcooling - LESS THAN 350F
- 2) IF SI is required. THEN perform the following:
a) Manually actuate both trains of SI and Containment Isolation.
b) OBSERVE NOTE PRIOR TO
.STEP 5 and go to Step 5.
- 3) LF SI is NOT required. THEN perform the following:
a) Start monitoring Critical Safety Functions per CSP-ST.O UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to EOP-0.1 UNIT 1.
REACTOR TRIP RESPONSE.
BOTH TRAINS ACTUATED b. Manually actuate both trains of
- b. Check SI -
SI and Containment Isolation.
"*SI pumps - BOTH RUNNING
"* RHR pumps BOTH RUNNING
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 8 of 33 I
I ACTION/EXPECTED RESPONSE I J
I RESPONSE NOT OBTAINED NOTE Foldout page shall be monitored throughout the remainder of this procedure.
5 Verify Automatic Actions Per ATTACHMENT A. AUTOMATIC ACTION VERIFICATION. While Continuing With This Procedure
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 9 of 33 Li I ACTION/EXPECTED RESPONSE I I
]
RESPONSE NOT OBTAINED I
I CAUTION If motor-driven auxiliary feedwater pump flow is greater than 240 gpm. its motor breaker may trip due to over current.
6 Verify Secondary Heat Sink Available:
- a. Check level in at least one S/G - a. Establish AFW flow as follows:
GREATER THAN [51%) 29V
- 1) Manually start pumps and align valves as necessary to establish AFW flow greater than or equal to 200 gpm.
- 2) IF AFW flow greater than or equal to 200 gpm can NOT be established. THEN perform the following:
a) Start monitoring Critical Safety Functions per CSP-ST.0 UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to CSP-H.1 UNIT 1.
RESPONSE TO LOSS OF SECONDARY HEAT SINK.
- b. Control pumps and align valves as necessary to maintain S/G level between [51%] 29% and 65%
POINT BEACH NUCLEAR PLANT EOP-0 UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 10 of 33 STEP I I ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED IY 7 Verify RCP Seal Cooling: IF seal cooling to any RCP is lost.
THEN reestablish seal cooling:
o Check labyrinth seal AP - GREATER THAN 20 INCHES a. Stop affected RCP(s).
OR "o iP-lA. loop A "o IP-lB. loop B o Check component cooling to RCP thermal barrier - NORM4AL b. Start pumps and align valves as necessary to reestablish component cooling water flow to all RCP thermal barriers.
- c. IF all charging pumps are stopped. THEN reestablish seal injection flow:
- 1) Ensure adequate power is available to run one charging pump. Refer to AOP-22"UNIT 1.
EDG LOAD MANAGEMENT. for KW ratings.
- 2) Start one charging pump at minimum speed for seal injection.
o IP-2A. train A o IP-2B. train A o 1P-2C. train B
POINT BEACH NUCLEAR PLANT, EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 11 of 33 I In% nT" I- IV I I I I* * * **RE*P*NSE* NOT OBTAINED*
- 8 Verify RCS Temperature Control: Perform the following: *
- a. Check RCS wide range cold leg 1. IF RCS cold leg temperature less than 547'F AND RCS temperatures *
- temperatures: *
- are trending lower. THEN
- follows:
- AND *
- a) Stop dumping steam.
- *STABLE *
- b) IF cooldown continues. THEN
- control feed flow:
- 1) Reduce total feed flow.
- 2) Maintain total feed flow
- greater than or equal to
- 200 gpm until level greater
- than [51%] 29% in at least one S/G.
- c) IF cooldown can NOT be stopped
- by controlling feed flow. THEN
- isolate steam lines:
- 1) Shut both main steam
- isolation valves.
- "a lMS-2018 for S/G A
- "* 1HS-2017 for S/G B
- 2) Ensure main steam isolation
- bypass valves - BOTH SHUT
- lMS-234 for S/G A *
- a IMS-236 for S/G B *
- 2. IF RCS cold leg temperature *
- temperature trending higher. THEN
- stabilize RCS temperature at or
- below 5471F as follows:
o Dump steam to condenser. *
, o Dump steam using atmospheric
, steam dumps.
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 12 of 33 E I ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED IF PZR pressure less than 2335 psig.
I 9 Check PZR PORVs - BOTH SHUT THEN stop PORV flow:
0 IRC-430
- b. IF any PORV can NOT be shut. THEN isolate that PORV:
- 1) Manually shut associated block valve.
"o IRC-515 for IRC-431C "o IRC-516 for IRC-430
- 2) IF any open PORV can NOT be isolated. THEN perform the following:
a) Start monitoring Critical Safety Functions per CSP-ST.O UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to EOP-1 UNIT 1. LOSS OF REACTOR OR SECONDARY COOLANT.
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 13 of 33 ACTION/EXPECTED RESPONSE I RESPONSE NOT OBTAINED 10 Verify PZR Spray Valves Shut:
- a. Check normal spray valves - BOTH a. IF PZR pressure less than SHUT 2260 psig. THEN stop spray flow:
a 1RC-431A. loop A 1) Manually shut both spray
- IRC-431B. loop B valves.
- 2) IF any spray valve can NOT be shut, THEN place manual override switch to close for failed spray valve(s).
"o IRC-431A-S for 1RC-431A "o IRC-431B-S for 1RC-431B
- 3) IF any spray valve can NOT be shut using manual override.
THEN stop RCP supplying failed spray valve(s).
o For IRC-431A, stop RCP A o For IRC-431B. stop RCP B
- b. Check auxiliary spray valve b. Stop auxiliary spray flow:
SHUT
- 1) Manually shut auxiliary spray a 1CV-296 valve.
- 2) IF auxiliary spray valve can NOT be shut. THEN minimize charging and shut charging line flow control valve.
- IHC-142 11 Check If RCPs Should Remain Running:
- a. Check RCPs - ANY RUNNING a. Go to Step 12.
- b. Check RCS subcooling based on b. IF at least one SI pump is core exit thermocouples running AND SI pump capable of GREATER THAN OR EQUAL TO delivering flow. THEN stop both
[600F] 30OF RCPs.
"* IP-lA. loop A
"* IP-lB. loop B 12 Start Monitoring Critical Safety Functions Per CSP-ST.O UNIT 1.
CRITICAL SAFETY FUNCTION STATUS TREES
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 14 of 33 lIi =JII ACIO/EPETD ESONERESPONSE INEXE~RSOS I I NOT OBTAINED
- 13 Verify Containment Sump *
- Recirculation Not Required: *
, EOP-1.3 UNIT 1, TRANSFER TO *
- CONTAINMENT SUMP RECIRCULATION.
- 14 Check If Secondary System Is Intact: IF any S/G is faulted. THEN go to EOP-2 UNIT 1, FAULTED STEAM
& No S/G pressure trending lower in GENERATOR ISOLATION.
an uncontrolled manner AND e No S/G completely depressurized 15 Check If S/G Tubes Are Intact: IF conditions indicate a S/G tube rupture. THEN go to EOP-3 UNIT 1,
"*Check secondary system radiation STEAM GENERATOR TUBE RUPTURE.
levels - NORMAL
- a. Condenser air ejector
" 1RIE-215
"* RE-225
- b. S/G blowdown
"*1RE-219
"* 1RE-222
"*1RE-231 for S/G A
"* 1RE-232 for S/G B
"*Request local surveys of main steam lines
"*Request Chemistry to prepare for periodic activity samples of both S/GCs I
POINT BEACH NUCLEAR PLANT, POINT BEACH NUCLEAR PLANT, EOP-0 UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 15 of 33 I I I E E I ACTION/EXPECTED RESPONSE I l RESPONSE NOT OBTAINED 16 Check If RCS Is Intact Inside Go to EOP-1 UNIT 1. LOSS OF REACTOR Containment: OR SECONDARY COOLANT.
- a. Check containment radiation levels - NORMAL
- 1) Containment
"*1RE-102. train A
"*1RE-107. train A
- 2) Containment high range
"*IRE-126. train A
"*IRE-127. train A
"*IRE-128. train A
- b. On 1C20. check containment sump "A" level - NORMAL
"*1LI-958. train A
"*1LI-959. train A "c. Check containment pressure NORMAL
1 POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 16 of 33 ISTE II ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED m .I
- 17 Check If SI Should Be Terminated: *
- a. Check RCS subcooling based on a. Go to Step 18.
- core exit thermocouples - GREATER -k
- THAN 350 F
- b. Verify secondary heat sink: b. IF neither condition satisfied.
- THEN go to Step 18. A
- -A o Level in at least one SIG
- -A GREATER THAN 29%
- -A
- o Total feed flow to S/Gs
- GREATER THAN OR EQUAL TO
- 200 GPM
- c. Check RCS pressure: c. Go to Step 18.
- Pressure - GREATER THAN
- 1600 PSIG
- AND
- Pressure - STABLE OR TRENDING
- HIGHER
- d. Check PZR level - GREATER THAN d. Raise PZR level:
- 10% *
- 1) Raise charging flow.
- 2) Go to SteD 18.
- TERMINATION *
- 18 Stabilize S/G Levels:
- a. Maintain total feed flow greater *
- a. Check S/G levels - GREATER THAN
- 29% than or equal to 200 gpm until
- level in at least one S/G is
- greater than 29%.
- b. Control feed flow to maintain SIG b. IF level in any S/G continues to
- levels between 29% and 65% rise in an uncontrolled manner.
- THEN go to EOP-3 UNIT 1. STEAM GENERATOR TUBE RUPTURE.
,*********************************************************************...1
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 17 of 33 I I I ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED I 19 Check If SIG Tubes Are Intact: IF conditions indicate a S/G tube rupture. THEN go to EOP-3 UNIT 1.
" Check secondary system radiation STEAM GENERATOR TUBE RUPTURE.
levels - NORMAL
- a. Condenser air ejector
"*1RE-215
"* RE-225
- b. S/G blowdown
"* 1RE-219
"*1RE-222
- c. Main steam line 1RE-231 1 for S/G A
- "RE-232 for S/G B
"*Request local surveys of main steam lines
"* Request Chemistry to prepare for periodic activity samples of both S/Gs CAUTION If .offsite power is lost after SI reset, manual action may be required to restart safeguards equipment.
20 Reset SI 21 Reset Containment Isolation 22 Reset IB-03 And IB-04 Non-Safeguards Equipment Lockouts
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-O UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 18 of 33 L Is I ACTION/EXPECTED RESPONSE I II RESPONSE NOT OBTAINED I CAUTION Placing loads on energized AC safeguards buses in excess of the power source's capacity could result in loss of the power source. Refer to AOP-22 UNIT 1. EDG LOAD MANAGEMENT. for KW ratings.
- 23 Check 4160 Vac Safeguards Buses - Monitor EDG loading per *
- : while continuing with this *
- P 1A-05. train A procedure. *
- 1A-06. train B 24 Reestablish Instrument Air To Containment:
- a. Start second instrument air compressor o K-2A o K-2B
- b. Check instrument air header b. Start service air compressors as pressure - GREATER THAN 80 PSIG necessary to establish instrument air header pressure greater than 80 psig.
o K-3A o K-3B
- c. Open one and then open the other c. IF no valve can be opened. THEN instrument air containment gag open one valve as follows:
isolation valve
- 1) Manually hold valve switch in
"* lIA-3047 open position.
"*lIA-3048
- 2) Locally gag open valve.
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 19 of 33 SII ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED I 25 Check If RCS Is Intact Outside Perform the following:
Containment:
- 1. Evaluate cause of abnormal
- a. Request local radiation surveys conditions.
in auxiliary building
- 2. IF cause is a loss of RCS
- b. Check auxiliary building inventory outside containment.
radiation levels - NORMAL THEN go to ECA-1.2 UNIT 1, LOCA OUTSIDE CONTAINMENT.
"*PPCS RMS screen. Page 104
"* (New PPCS RMS GRID screen)
"*Local surveys
- c. Check'auxiliary building sump levels - NORMAL
"*COlA 1-11. AUXILIARY BUILDING
-19 FT SUMP LEVEL HI - NOT LIT
"*COIA 2-11. AUXILIARY BUILDING NORTH SUMP LEVEL HI - NOT LIT "aCOA 3-11. AUXILIARY BUILDING SOUTH SUMP LEVEL HI - NOT LIT 26 Check PZR Relief Tank Conditions Evaluate cause of abnormal NORMAL conditions.
"*Pressure
"*Temperature
"*Level 27 Check If RHR Pumps Should Be Stopped:
- a. Check RCS pressure - GREATER THAN a. Go to EOP-1 UNIT 1, LOSS OF 200 PSIG REACTOR OR SECONDARY COOLANT.
TRENDING HIGHER
- c. Stop both RHR pumps IP-10A. train A IP-10B. train B
- han 200 psig uncontrolled manner to less than *
- 200 psig. THEN restart RHR pumps *
"to supply water to RCS.
- POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 SAFETY RELATED EMERGENCY OPERATING PROCEDURE Revision 36 12/14/2001 Page 20 of 33 REACTOR TRIP OR SAFETY INJECTION a I I Li I ACTION/EXPECTED RESPONSE
RESPONSE
I I RESPONSE NOT OBTAINED ACTION/EXPECTED IVerify 28 Charging Flow:
- a. Ensure RCS Loop A Cold Leg Normal Charging Isolation Valve - OPEN
- b. Check charging pumps - AT LEAST b. Perform the following:
ONE RUNNING
- 1) IF component cooling water "o IP-2A. train A flow to any RCP thermal "o IP-2B. train A barrier is lost. THEN locally "o 1P-2C. train B shut affected RCP(s) seal injection throttle valve before starting charging pumps.
o lCV-300A. RCP A o.1CV-300B. RCP B
- 2) Start charging pumps as necessary to establish at least one running.
- c. Start additional charging pumps and adjust speed on running charging pumps as necessary to establish desired charging flow
- d. Adjust charging line flow controller as necessary to maintain labyrinth seal &P greater than 20 inches e 1HC-142 29 Check If Diesels Should Be Stopped:
- a. Check 4160 Vac safeguards buses a. Restore offsite power to 4160 Vac ENERGIZED BY OFFSITE POWER safeguards buses.
o IA-05. train A e 1A-06. train B
- b. Stop all unloaded EDGs:
o OP-I1A G-01. EMERGENCY DIESEL GENERATOR G-01 "o OP-11A G-02. EMERGENCY DIESEL GENERATOR G-02 "o OP-lIB. EMERGENCY DIESEL GENERATOR G-03 (G-04)
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 21 of 33 I ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED I 30 Ensure Miscellaneous Electrical Loads Are Energized:
- a. Ensure MCCs - ENERGIZED
"* 1B-31. IB52-14C. train A
"*B-43. 1B52-21C. train B
- b. Check battery chargers supplying b. Restore battery chargers:
DC buses - ENERGIZED
- 1) Close affected battery charger "o D-07 supply contactor.
"o D-09 "o D-108 2) IF contactor does NOT close OR "o D-109 battery charger will NOT operate. THEN restore battery chargers per AOP-0.0. VITAL DC SYSTEM MALFUNCTION. while continuing with this procedure.
- c. Ensure cavity cooling fan - ONE RUNNING "o IW-4A. train A "o 1W-4B. train A
- d. Check cable spreading room d. Restore cable spreading room ventilation operating: ventilation per 01-90. CONTROL.
COMPUTER. AND CABLE SPREADING
- 1) Check cable spreading room ROOM VENTILATION SYSTEMS.
recirc fans - ONE RUNNING "oW-13A1 "oW-13A2
- 2) Check CSR chilled water recirc pumps - ONE RUNNING o P-1lIA o P-111B
- e. Start additional loads as necessary to meet current plant conditions. Refer to AOP-22 UNIT 1. EDG LOAD MANAGEMENT 31 Return To Step 8
- E14D -
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 22 of 33 ONSE NOT OBTAINED IsJ I ACTION/EXPECTE D RESPONSE i I RS I ATTACHMIENT A (Page 1 of 10)
AUTOMATIC ACTION VERIFICATION Al Verify Feedwater Isolation:
- a. Check main feed lines isolated: a. IF any main feedline can NOT be isolated. THEN perform the
- 1) Feedwater regulating control following:
valves - BOTH SHUT a) Trip main feed pumps.
- IP-28B
- 2) Feedwater regulating bypass valves - BOTH SHUT b) Place condensate pumps in pull-out.
- IdS-480 for S/G A "*IP-25A 1
"CS-481 for S/G B
"*IP-25B c) Stop heater drain tank pumps.
"*IP-27A
"*IP-27B
"*IP-27C
- b. Check main feed pumps - BOTH b. Trip main feed pumps.
TRIPPED
"* IP-28A
"* lP-28B
SHUT
- 1CS-2190. train A
- 1CS-2189. train B
__j
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 23 of 33 ONSE NOT OBTAINED
.= =J ACTI ON/EXPECTED RESPONSE I I I ATTACHMENT A (Page 2 of 10)
AUTOMATIC ACTION VERIFICATION A2 Verify Containment Isolation:
- a. Check containment isolation a. Perfor:m the following:
panels "A" and "B" - ALL LIGHTS LIT 1) Manlually actuate Containment Isolation.
- 2) IF any valve open AND flow path NOT required. THEN shut valve(s). Refer to ATTACHMENT B.
- b. Check other valves - SHUT b. Manually shut valve(s).
"*RS-SA-9 . Unit 1 steam supply to rad waste system
"*Any valve which may be open under administrative control A3 Verify AFW Actuation:
BOTH RUNNING
- 1) Ensure steam supply valves to
- P-38A, train A turbine-driven AFW pump - BOTH
- P-38B. train B OPEN
"*lMS-2020. train A
"*IMS-2019, train B
- 2) WHEN SI sequence complete.
THEN manually start motor-driven AFW pumps.
- b. Check S/G levels - BOTH LESS THAN b. Go to Step A4.
[51%] 25%
- c. Ensure steam supply valves to turbine-driven AFW pump - BOTH OPEN
- lMS-2020. train A
- IMS-2019. train B
POINT BEACH NUCLEAR PLANT EOP-O UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 24 of 33 S II ACTION/EXPECTED RESPONSE I RESPONSE NOT OBTAINEDI ATTACHMENT A (Page 3 of 10)
AUTOMATIC ACTION VERIFICATION WHEN SI sequence complete. THEN A4 Check SI Pumps - BOTH RUNNING establish SI flow as follows:
"a1P-15A. train A
- a. Manually start SI pumps.
"l P-15B. train B
- b. IF any SI pump can NOT be started. THEN isolate system boundary as follows:
- 1) Place affected SI pump in pull-out.
- 2) Ensure affected SI pump suction valve shut.
o ISI-896A. train A o lSI-896B. train B BOTH RUNNING WHEN SI sequence complete. THEN A5 Check RHR Pumps -
establish RHR flow as follows:
"* IP-IOA. train A
- a. Manually start RHR pumps.
"* IP-IOB. train B
- b. IF any RHR pump can NOT be started. THEN isolate system boundary as follows:
- 1) Place affected R.HR pump in pull-out.
- 2) Ensure affected RHR pump suction valve shut.
o ISI-856A. train A o ISI-856B. train B I
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 25 of 33 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED I P
I ATTACHMENT A (Page 4 of 10)
AUTOMATIC ACTION VERIFICATION A6" Check Component Cooling Water Pumps Establish one component cooling water pump running as follows:
- ONLY ONE RUNNING
- a. IF no component cooling water o iP-IIA. train A pump running. THEN perform the o iP-IIB. train B following:
- 1) Stop all RCP(s).
"i P-lA. loop A
" 1P-IB. loop B
- 2) Manually start one component cooling water pump by placing control switch to stop and then auto-after-stop.
- 3) Match flags for running and stopped pumps.
- b. IF both component cooling water pumps running. THEN place one pump in standby.
POINT BEACH NUCLEAR PLANT EOP-0 UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 26 of 33 SACTI ON/EXPECTED RESPONSE I I l
RESPONSE NOT OBTAINED I I CINEPCTDRSOS ATTACHMENT A (Page 5 of 10)
AUTOMATIC ACTION VERIFICATION A7 Verify Service Water System Alignment:
- a. Check service water pumps - SIX a. WHEN SI sequence complete. THEN RUNNING manually start pumps.
0 P-32A. train A 0 P-32B, train A 0 P-32F. train A S P-32C. train B 6 P-32D. train B 0 P-32E. train B
- b. Check service water isolation b. Perform the following:
valves - SHUT
- 1) Manually shut valve(s).
"*At least one spent fuel pool heat exchanger A isolation MOV 2) IF any isolation valve will NOT shut. THEN locally shut o SW-2927A. inlet MOV valve or associated manual o SW-2930A. discharge MOV isolation valve.
"*At least one spent fuel pool heat exchanger B isolation MOV "o SW-2927B, inlet MOV "o SW-2930B. discharge MOV
"* At least one auxiliary building A/C condenser isolation MOV o SW-2816. train A o SW-4479. train B
"*At least one water treatment system inlet MOV "o SW-4478. train A "o SW-2817. train B
- c. Locally at blowdown evap panel c. Perform the following:
C-180. check at least one radwaste service water valve shut 1) Locally shut valVe(s).
o SW-LW-61. train A 2) IF any valve will NOT shut.
o SW-LW-62. train B THEN locally shut associated manual isolation valve.
POINT BEACH NUCLEAR PLANT EOP-0 UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 27 of 33 p p p LI[ ACTION/EXPECTED RESPONSE I I I
RESPONSE NOT OBTAINED I ATTACHMENT A (Page 6 of 10)
AUTOMATIC ACTION VERIFICATION AS Verify Containment Accident Cooling Units Running:
- a. Check containment accident a. WHEN SI sequence complete. THEN recirculation fans - ALL RUNNING manually start fans.
- IW-lAl. train A lW-lB1.
1 train A 1W-1Cl.
1 train B
- IW-lD1. train B
- b. Check containment ventilation b. Manually open containment ventilation cooler outlet cooler outlet emergency FCVs BOTH OPEN emergency FCVs.
e 1SW-2907. train A o 1SW-2908. train B
- c. Check annunciator C01B 2-3. c. Perform the following:
UNIT I CONTAINMENT RECIRC COOLERS WATER FLOW LOW - CLEAR 1) Ensure non-affected unit's service water isolation valves
- BOTH SHUT S2SW-2907 Train t A
- 2SW-2908 train t B
- 2) Isolate service water to non-safety loads as necessary to clear annunciator.
A9 Check Control Room Fans Armed:
- a. At MCC IB-32. depress Control
- a. Check Control Room Charcoal Circuit Arming pushbutton for Filter Fan W-14A - WHITE LIGHT OFF Control Room charcoal filter fan W-14A.
- b. At MCC IB-42. depress Control
- b. Check Control Room Recirc Fan WHITE LIGHT OFF Circuit Arming pushbutton for W-13B2 -
Control Room recirc fan W-13B2.
a IB52-428M
POINT BEACH NUCLEAR PLANT EOP-0 UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 28 of 33 ATTACHMENT A (Page 7 of.10)
AUTOMATIC ACTION VERIFICATION Align Control Room ventilation per A10 Check Control Room Ventilation - IN 01-90. CONTROL. COMPUTER. AND CABLE AN ACCIDENT MODE SPREADING ROOM VENTILATION SYSTEMS.
"*Control Room recirc fans - AT LEAST ONE RUNNING o W-13BI o W-13B2
"*Control Room damper solenoid valve
- PURPLE LIGHT LIT All Check If Main Steam Lines Can Remain Open:
- a. Go to Step A12.
- a. Check MSIVs - ANY OPEN
- b. Isolate both steam lines as
- b. Check containment pressure - LESS follows:
- 1) Shut both main steam isolation valves.
"* lMS-2018 for SIG A
" 1MS-2017 for S/G B
- 2) Go to Step A12.
- c. Ensure main steam isolation valve
- c. Check high-high steam flow on affected main steam line(s) bistable lights - NOT LIT shut.
o 1MS-2018 for S/G A o IMS'2017 for SIG B
- d. IF RCS average temperature is
- d. Check high steam flow bistable less than 543'F. THEN ensure main lights - NOT LIT steam isolation valve on affected main steam line(s) shut.
"o IMS-2018 for S/G A "o IMS-2017 for S/G B I
POINT BEACH NUCLEAR PLAI4T EOP-0 UNIT I POINT BEACH NUCLEAR PLANT EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 29 of 33 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED I l
ATTACHMENT A (Page 8 of 10)
AUTOMATIC ACTION VERIFICATION A12 Verify Proper SI Valve Alignment: Manually align pumps and valves as necessary to establish proper SI
- a. Check Unit 1 SI Active status alignment.
panel - ALL LIGHTS LIT
- b. Check Unit 1 SI - Spray Ready status panel - NO LIGHTS LIT
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 36 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 30 of 33 I SEPIIACTION/EXPECTED RESPONSE IRESPONSE NOT OBTAINED ATTACHMENT A (Page 9 of 10)
AUTOMATIC ACTION VERIFICATION
- A13 Verify Containment Spray Not Establish containment spray as
- follows: *
- Required:
- a. Check containment pressure 1. Check containment spray actuated:
- recorder HAS REMAINED LESS THAN
- 25 PSIG
- Annunciator {CO1 B 2-61. *
, CONTAINMENT .SPRAY - LIT *
- IPR-968
- e 1PR-969 2. IF containment spray has NOT *
, actuated. THEN manually actuate *
, containment spray. *
, 3. Verify the following equipment *
, status: *
, a) Ensure containment spray pump *
, discharge MOVs - ALL OPEN *
, a ISI-860A for IP-14A *
, e ISI-860B for IP-14A
- ISI-860C for 1P-14B *
, b) Ensure containment spray pumps
, - AT LEAST ONE RUNNING *
,o IP-A. train A*
o IP-14B. train B *
, c) Shutdown one train of *
, containment spray as follows: *
, containment spray Place inonepull-out.*
1)~pump
- o 1P-14A. train A *
, o IP-14B. train B *
, 2) Ensure suction on idle *
, spray pump shut.
- o SI-870A for *P-IA
, d) WHEN containment spray has *
, been actuated for greater than *
, two minutes. THEN ensure at *
, least one spray additive eductor suction valve open. *
, o ISI-836A. train A *
, o ISI-836B. train B
POINT BEACH NUCLEAR PLANT LUU UJ4+/-L i.
POINT BEACH NUCLEAR PLANT SAFETY RELATED EMERGENCY OPERATING PROCEDURE Revision 36 12/14/2001 Page 31 of 33 REACTOR TRIP OR SAFETY INJECTION STEP ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED I
OBTAINED I RESPONSE NOT ATTACHMENT A (Page 10 of 10)
AUTO4ATIC ACTION VERIFICATION A14 Verify SI Flow:
- a. Return to procedure and step in
- a. Check RCS wide range pressure effect.
LESS THAN 1400 PSIG
- b. Manually start pumps and align
"a1FI-925. train A
" 1FI-924. Train B
- c. Return to procedure and step in
- c. Check RCS wide range pressure effect.
LESS THAN [425 PSIG] 200 PSIG
- d. Manually start pumps and align
- d. Check RER pumps - FLOW INDICATED valves as necessary to establish RER pump flow.
"*1FI-626. train A
"*1FI-928. train B
-END-I
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 POINT BEACH NUCLEAR PLANT SAFETY RELATED EMERGENCY OPERATING PROCEDURE Revision 36 12/14/2001 Page 32 of 33 REACTOR TRIP OR SAFETY INJECTION ATTACHMENT B (Page 1 of 2)
CONTAINMENT ISOLATION VALVES PANEL A COMPONENT DESCRIPTION TRAIN Auxiliary charging line A 1CV-1296 Pressurizer relief tank to gas analyzer A 1RC-538 Reactor coolant drain tank to gas analyzer A 1WG-1788 Reactor coolant drain tank to -19 ft sump A 1WL-1698 Reactor coolant drain tank pump suction A 1WL-1003A Reactor coolant drain tank pump suction A 1WL-1003B Reactor makeup water to containment A or B IRC-508 Pressurizer relief tank to gas analyzer B 1RC-539 Reactor coolant drain tank'to gas analyzer B IWG-1789 Accumulator nitrogen supply A or B 1SI-846 Reactor coolant drain tank pumps suction B IWL-1721 Containment purge supply A IVNPSE-3244 Containment purge exhaust A IVNPSE-3212 Sump A drain A 1WL-1723 Pressurizer steam sample A 1SC-951 Pressurizer liquid sample A 1SC-953 Containment purge supply B 1VNPSE-3245 Containment purge exhaust B 1VNPSE-3213 Sump A drain B 1WL-1728 Pressurizer steam sample A or B 1SC-966A Pressurizer liquid sample A or B ISC-966B
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 SAFETY RELATED EMERGENCY OPERATING PROCEDURE Revision 36 12/14/2001 Page 33 of 33 REACTOR TRIP OR SAFETY INJECTION ATTACHMENT B (Page 2 of 2)
CONTAINMENT ISOLATION VALVES PANEL B DESCRIPTION TRAIN COMPONENT Component cooling water outlet from excess A or B 1CC-769 letdown heat exchanger Reactor coolant pump seal return A 1CV-313 Letdown line A iCV-371 Steam generator blowdown A or B lMS-5958 Steam generator blowdown A or B lMS-5959 Reactor coolant drain tank vent A 1WG-1786 B
1CV-313A Reactor coolant pump seal return B
1CV-371A Letdown line 1WG- 1787 Reactor coolant drain tank vent i- A 1RM-3200C RE-211/212 supply IRM-3200A i RE-211/212 return A or B IRM- 3200A IHS-2083 Steam generator A sample A or B lMS-2083 v A or B Steam generator B sample lMS-2084 A
1SC-955 Reactor coolant hot leg sample A or B IIA-3047 Instrument air line B
IRM-3200B RE-211/212 supply A or B 1SC-966C Reactor coolant hot leg sample
- A orB:
IIA-3048 Instrument air line
-END-
FOLDOUT PAGE FOR EOP-0 UNIT 1
"*RCS subcooling - LESS THAN [600F] 30OF
"*SI pumps - AT LEAST ONE RUNNING AND CAPABLE OF DELIVERING FLOW "aOperator controlled cooldown - NOT IN PROGRESS
- 2. FAULTED SIG ISOLATION CRITERIA IF any SIG pressure trending lower in an uncontrolled manner OR any S/G completely depressurized. THEN the following may be performed:
- a. Isolate feed flow to faulted SIG.
- b. Maintain total feed flow greater than or equal to 200 gpm until narrow range level in at least one S/G is greater than [51%] 29%.
- 3. RUPTURED S/G ISOLATION CRITERfA IF any S/G level rises in an uncontrolled manner OR any S/G has abnormal radiation. AND narrow rangd level in affected S/G(s) is greater than [51%] 29%. THEN feed flow may be isolated to affected SIG(s).
- 4. AFW SUPPLY SWITCHOVER CRITERIA IF CST level lowers to less than 8 feet. THEN switch to alternate AFW suction supply per AOP-23 UNIT 1. ESTABLISHING ALTERNATE AFW SUCTION SUPPLY.
- 5. ADVERSE CONTAINMENT CONDITIONS IF any condition listed below occur~s. THEN adverse containment setpoint values in brackets. [). shall be used:
o Containment pressure - GREATER THAN 10 PSIG OR o Containment radiation level - GREATER THAN OR EQUAL TO 10' R/HR OR o Integrated dose to containment - GREATER THAN 10' R
- 6. AFW MINIMUM FLOW REQUIREMENTS IF any AFW pump mini-recirc valve fails shut. THEN maintain minimum flow or stop the affected AFW pump as necessary to control S/G levels.
o P-38A minimum flow - GREATER THAN 50 GPM o P-38B minimum flow - GREATER THAN 50 GPM o P-29 minimum flow - GREATER THAN 75 GPM
Se N0 I /'
Nuclear Power Business Unit TEMPORARY CHANGE REVIEW AND APPROVAL Note: R'?efer to .VP 1.2 3. TerrporaryProcedureChanges,for requirenents. Page I of ,
I - L-IlTLATION Doc Number EOP-0 Cunent Rev 36 Unit PB1 Temp Change No.7 Docdmcnt Title REACTOR TRIP OR SAFETY -NJECTION Existing Effectivc Temporary Changes Brief Description MODIFY FOP FOR MINIMTUM AMF FLOW TO INCLUDE LOW LA HDR PRESSURE (Identify spcific chxngi.' on Form PBF-0026c, Document Review and .Approval Cortnti=nm, and include with the package) 0 Initiate PBF-0026h and include with the chanye.
Other documents required to be effectivc concurrently with the temporary change:
Changes pre-screened according io NP 10.3.17
- NO 0U YES (ifYes.listfren= a-d cniter cn P2F.oo26dcXrefLr =\? 103 1)
Screening compicctd according to NT- 10.3.1? U NA CE YES Safety Evaluatic.; Required? [D NO 0i YES fMy.. a,ý=rw r*medrna ....... $',A-Lm-dlvre-,-:*-.t,.-*
Determine if the change constitutes a Change Orfntent to the procedure by evaluating the folloiing questions tlf an) ans%%crs are YES. a rcision may be procesaed or final rev'rws and approvals shall be obtazr:d before implementing)
Will the proposed change: YES NO
- 1. Require a change to. affect or invalidate a requirem-zt., commitment, evaluation or description in the Current Licensing Basis (as defined in NP 10.3.1)?
2 Cause an increase in magnitude, significance or impact such tl:tat it should be processed as a E] E re- ision?
- 3. Delete cir modify a prerequisite, initial condition, precaution, limitation )r other steps that U could have safety significance or affect the procedure's margin of safety?
- 4. Delete QC hold points, Independent Verification or Concurrent Check steps withnut the U 0 related step(s) that require the performance also being deleted?
- 5. Change Tech Spec or other regulatory acceptance criteria other than for re-baselining U 0 purposes?
- 6. Require a change to the procedure Purpose or change the procedu 7 e 5 9i'cati/?
Initiated By (prinL!Sign) M_,g Date' V2-01 Z fl - INITIAL APPROVAL This change is correct and complete, can be performed as written, and does not 2der!*V ect pecenncl or nuclear safety or Plant nneratingconditions,..
Group Supervisor (pri~l') I(Cannot be the Vitiator) at I I This change does not adversely affect Plant operating conditions. (Safety Rela- pr ed(res only) 1 Senior Reactor Operator (prinL'sip) (V\ , .. I .t -/-'* Datc/' /Zo. C/1 tCannot be thdtnitiatoror Group Supenisor)
WsLisnot be thchriltEsitoror Group ýupenlsor)
.\
Ili III - PROCEDURE OAVNER REVIEW 0 Permanent Ul Orne-time Use U] Expiration Date, Event or Condition:
U,).old change until procedure completed (final revieiw and approval still required within 14 da3 s of initial approval)
JO QRfMSS Revicw NOT Required (Adinin.NNSR only) [ QR.Review Required1 U MSS Revieý%Pcqtiired CRe'.encz \F 1 65 Procedure Owner (print/sign) _ i "//d- " Date Thi' Chanec and sunno-tine reauirements corree..lv corg1eted and processed _ _ __,_
IV - FINAL REVIEWV AND APPROVAL (Must he completed vwithin 14 days of initial approial) (The Initiator, QR wrod Approsal Authoritq shall be independent from each other)
~j~6IDate I
QRýIMSS (prntsizn) _ _ _ _
- " indicates 50 59/72 48 applhcablty asscswd, y necessary t.rcening: e\aluanotis perfo*,.&1 determinatin nude a to *, et.er addit:,*ra L-Thuss..isciplhnzly review required, and ifrequired, performed.
MISS Meeting No. _________ ~*
ApproN al Authority (print'sign) 7). - A,---* .z Date / C,.--2!
V -REVISION INFORMATION FOR PERj",IAN'E3N* CHANGES
(? / / - Dg Date /
Post "ypng Rcview (.rm--siv)
Indicates ;enipcrar changc(s) mcorpora.*d c2aalIN as appro ed and no oJTe" chu.,nes made to dzucn Incorporated into Revision Number EffectOve DateJA. :' ij, ,,
1;EC'D J AN ! 1 200,2 ,. . ,.
'BtF-0026c ., . -
- Rcfcrt.nree NP' 1 2 3 Re%mon 12 110599
C Point Beach Nuclear Plant DOCUMENT REVIEW AND APPROVAL CONTINUATION Page .L of Doc Number EOP-0 Revision 36 Unit Title REACTOR TRIP OR SAFETY INJECTION Tcmporan" Change Number 7eC/J - . oo -o9,'
Dcscription of Changes:
Step C*hange[Reason CHANGE: ADDED REFERENCE TO ANNUNCIATOR COI A 1-9, IA Y-ADER LOW PRESSURE FOR THE AFW .INIMUM FLOW REQUIREMENTS.
4-. FOLDOUT REASON: TO ENSURE MINIMUM FLOW IS MAINTAI*.NED THROUGH THE AFW PUMPS PAGE DURIG OPERATION.
4-IJ
+
I 4
__________________________________I i-
____________________ ~~~I-____________________________ __________
I-I I1 I
I I-I I4 V.
-4 I -
'-'I
__________________________________I Other Comments
,:.r c: ',:.- I,.-', :". 1.r. .I-'
- Not. R.ordmrg of SLcp Nwubcr(s is r.ot rcquircd for muhiph, ocurrccs of identica!
i ,131-.0 0 4,,1 0 N.,
)e Point Beach Nuclear Plant TEMPO RARY CHANGE AFFECTED ML-kNUAL LOCATION Page of I Proccdurc Number EOP-O Revision 36 Unit PB1 Title REACTOR TRIP OR SAFETY INJECTION Temporary Change Number 7" gZop" oo,-' T I - IMMEDIATELY AFTER INITIAL APPROVAL ON PBF-0026e (Nen-Intent changes)
(after Final Approal if change of intent indived)
This procedure change has been processed as fellows: (Manual/Locationr) Date IPerform, d Ul Copy included in work package for field implementation. (WO No. ) _ _
[D Copy filed in Control Room temp change binder (Operations only). I [ )... -e Z Original change package provided to V-S.vo to obtain Procedure Owner Review (e g O,,er re-,iew may be coordinated by In-Group OA II. Procedure *Wnter,Procedu-e Super%isor, ctc.)
Performed By (.print and sign) .t-,*,g~~~=**e- /C/_ZDate /; --;P- C=t 11 - PROCEDURE, OWINER REVIEW ON PBF-0026e (may be performed by OA li, Procedure Writer, et¢.)
S Date This procedure change has been processed as follows: (Manual/Location) Performed
[* Copy sent to Document Control Distribution Lead for Master File (Net required for one-time use change)! , ,2¢ *
[] Copy filed in Grout) satellite file. (No- required for crie-time use ch-a.nccs )
[] Copy filed in Group one-time use file.
[] Original Temp Change providcd to _*" ,to obta'*i.- Fina! Approvals i (c S., final appro* al may be coordmirtcd b%In-Grotip 0-k It. Proc.-du-e W\nter. Procedure SL-.)-."\ i.l-0,. ,Ct)Z L"*c .,
9 U_
Performcd By (print and sign) -.. /I L -, Date -,c- -
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l-Point Beach Nuclear Plant SCR .
10 CFR 50.59/72.48 SCREEPLNG (NEW RMLE) Vcnf SCRnuýona!' pages 6T,...,,Page 2 Does the proposed activity in%olve a change to the terms, conditions or specifications incorporated in any VSC-2-4 cask Certificate of Compliance (CoC)? Changes to a VSC-24 cask Certificate of Compliace require a CoC am.endmen: request.
[] Yes [D No If a storage cask Certificate of Compliance change is required, explain wli-t the change should be and iNhy it is required.
10 CFR 50.59 StCREENING-----*-G PART 11 (50.59) - D)ETERMINE IF THE CHANGE -NVOLVESA DESIGN FUNCTION (Resource Manual 5.3.2)
Compare the proposed activity to the relevant CLB descriptions, =nd answer the following questions:
YES NO QUESTION
[] [ Does the proposed activity involve Safety Analyses or structures, systems and components (SSCs) credited in the Safert Analyses?
El [] Does the proposed activity involve SSCs that support SSC(s) credited in the Safety Analyses?
l [] Does the proposed activity involve SSCs whose failure could initiate a 'ransient (e.g, reactor trip, loss of feedwatcr, ctc.) or accident, OR whose failure could impact SSC(s) credited in the Safety Analyses?
El [] Does the proposed activity involve ( LB-described SSCs or procedural controls that perform functions that are required by, or otherwise necessary .o comply with, regulations, license coniditions, orders or technical specifications?
"- 0] Does the activity involve a method ofevaluction described in the FSAR?
0 Isthe activity a test or cxperimenl? (i.e., a non-passive activity which gathers data)
E] 0 Does the activity exceed or potentially affect a design basislimitfor afissionproduct barrier(DBLFPB)?
(NOTE: If THIS questions is answered YES, a 10 CFR 50.59 Evaluation is required.)
If the ansyers to ALL of these questions are NO, mark Part Tll as not applicable, document the 10 CFR 50.59 screening in the conclusion section (Part IV), then proceed directly to Part V - 10 CFPR 72.48 Pre-screening Questiors.
If any of the abo' c questions -aremarked YES identiRy below the specific design function(s), men-hod of evaluation(s) or DBLFPB(s) involved.
FSAR 10.2 ,,staes each AFW pump has an ACV controlled recire line back to the CST to ensure minimum flow to dissipa-e heat. This change ensures the minimum AFW flow requiremM.ts will be maintained on any running AFW pump in the case of a failed shut AFW mini-rccirc flow control v--lsve PART m (50.59) - DETERIMINE WHETHER TIHE ACTIVITY LNVOLVES ADVERSE EF FECTS (Resource Manual 5.3.3)
If ALL the questions in Part II are answered NO, then Part III is [] NOT APPLICABLE.
Aniswcr the following questions to determine if the activity has an ad%'erse effect on a design function. An) YES arsiwer means dt.t a 10 CFR 50.59 ENaluhtion is required, EXCEPT ,. here noted in Part 111.3.
II I CHANGES TO THE FACILITY OR PROCEDURES YES NO QUESTION El [0 Does the activity ad%ersel% affect the design function of an SSC credited in safet analyses?
PBF-1515c Rcisic.n 0 10*24 01 Re 'ercn -:-! NP 5 1 ,'
,=.OO,, - Go Point Beach Nuclear Plant SCR 27- _ __
10 CFR 50.59/72.48 SCREENING (NEW RULE) V.,%scR, 1i. 0: aupag.
1
-*/*) /- -O,*Page .3
[ Does the activity adversely affect the method of performing or controlling the design function of an SSC credited in the safety analyses?
if any ans%er is YES, a 10 CFR 50.59 Evaluation is required. If both answers are .NO. describe the basis for 'ie conclusion (attach additional discussion as necessary):
This change ensures that minimum recirc flow requirements as stated in FSAR I52 are not violazed.
111.2 CHANGES TO A METHOD OF EVALUATION (If the activity does not involve a method of evaluation, these questions are Z NOT APPLIC.xBLE.)
YES NO QUESTION r 5 Does the activity use a revised or different method of evaluation for performing safety analyses than that described in the CLB7
[] 5] Does the activity use a revised or different method of evaluation for evaluating SSCs credited in safety analyses than that described in the CLB?
Ifany answer is YES, a 10 CFR 50.59 Evalnotion is required. If bo-.h answers are NO. describe the basis for the conclusion (attach additional discussion, as necessaty).
111.3 TESTS OR EXPERIMENTS If the activity is not a test or experiment, the questions in IH.3.a and [].3.b are 0 NOT APPLICABLE.
- a. Answer these two questions first:
YES NO QUESTION 5 5 Is the proposed test or experiment bounded by other tests or experiments that arc described in the CLB?
rO [] Are the SSCs affected by the proposed test or experiment isolated from the facility' If the answer to BOTH questions in V.3.a is NO, continue to UI.3.b. If the ans%ý-er tn EITHER question is YES, then describe the basis.
- b. Answer these additional questions ONLY for tests or experiments 'ihich do NOT meet the criteria given in M 3.a abo; c.
If thii ansi cr to either question in I1.3.a is YES, then these three questions are [] NOT APPLICABLE.
YES NO QUESTION 5] [1 Does the activity utilize or control an SSC in a manner that is outside the reference bounds of the design bases as described in the CLB?
E [] Does the activity utilize or control an SSC in a manner that is inconsiscnt with the analyses or descriptiors in the CLB?
El n Does the activity place the facility in a condition not previously evaluated or that could affect the cap.ZbihlT of an SSC to perform its intended functions?
IfWan. ansN\er in lll.3.b is YES. a 10 CFR 50.59 Evaluation is required- If the ans%%ers in Il 3.b are ALL NO. desznbe dte basis for 'die conclusion (attach additionml discussion as necessary):
PI3F-I15Ic Fc.Crzrne "*:I -~
P.c~i-ion 0 10'24'01
Point Beach Nuclear Plant SCR 4--2o~
- oo0; 10 CFR 50.59/72.48 SCREENING (NTEW RULE) v'eriYSCRnumber onall pages
-40 -l -4o& Page 4 IV - 10 CFR 50.59 SCREENING CONCLUSION (Resource Manual 5.3.4).
Check all that apply:
A 10 CFR 50.59 Evaluation is El required or [0 )T required.
A Point Beach FSAR change is [] required or 0 NOT required. If an FSAR change is required, then initiate an FSAR Change Request (FCR) per NP 5.2.6.
A Regulatory Commitment (CLB Commnitcnt Database) change is E] required or Z NOT required. If a Regulatory Commitment Change is required, initiate a commitment change per NrP 5.1.7.
A Technical Specification Bases change is El required or 0D NOT required. If a change to the Technical Specification Bases is rcquired, then initiate a Technical Specification Bases change per NP 5.2.15.
A Technical Requirements Manual change is El required or 0 NOT required If a change to the Technical Requirements Manual is required, then initiate a Techtical Requirements Manual change per NP 5.2.15.
10 CFR 72.48 SCREENING NOTE: NEI 96-07, Appendix B. Guidelines for 10 CFR 72.48 Implementation should be used for guidance to determine the proper responses for 72.48 screenings.
PART V (72.48) - 10 CFR 72.48 INITIAL SCREENLNG QUESTIONS Part V determines if a full 10 CFR 72.48 screening is required to be completed (Parts VI and VII) for the proposed activity.
3NO QUESTION Does the proposed activity involve IN ANY MANNER the dry fuel storage cask(s), the cask tramnsferhran.zport equipment, any ISFSI facility SSC(s), or any IJSFS! facility monitoring as follows: Multi-Assembly S*ealed Basket (ISB), MSB Transfer Cask (MTC), MTC Lifting Yoke, Ventilated Concrete Cask (VCC), Ventilated Storage Cask (VSC), VSC Transporter (VCST), ISFSI Storage Pad Faciii)y, ISFSI Storage Pad Data/Communication Links, or PPCSIISFSI Continuous Temperature Monitoring System?
El 0 Does the proposed activity involve IN ANY MANNER SSC(s) installed in the plant specifically added to support cask loading/unloading activities, as follows: Cask Dewatering S)yem (CDNV), Cask Reflood System (CRF), or H) drogen Monitoring System?
El 0 Does the proposed activity involve IN ANY MANNER SSC(s) needed for plant operation which are also used to support cask loading/unloading activities, as follows: Spent Fuel Pool (SFP), SFP Cooling and Filtration (SF),
Primary Auxiliary Building Ventilation System (VNPAB), Drumming Area Ventilation S) stem (VNDRM),
RE-105 (SFP Low Range Monitor), RE-135 (SFP High Range Monitor), RE-221 (Drumming Area Vent Gas Monitor), RE-325 (Drumming Area Exhaust Low-Range Gas Monitor), PAB Crane, SFP Platform Bridge, Truck Access Area, or Decon Area?
El 0 Does the proposed activity involve a change to Point Beach CLB dcsign criteria for ex'.emal events such as earthquakes, tornadoes, high winds, flooding, etc.?
El [ Does the activity involve plant heavy load requirements or procedures for areas of the plant used to support cask loading/unloading activities?
El 0] Does the activity involve any pot .ntial for fire or ex.plosion %%herecasks ,re loaded, unloaded, transported or stored?
If ANN' of the Part V questions are ansm\ered YES, then a full 10 CFR 72.48 screenin- is rcquired and answers to the questions in t VI and Par VII are to be provided. If ALL the questions in Part V are ansi~ered NO. then check Parts VI and VII as not
. licable. Complete Part VIII to document the conclusion that no 10 CFPR 72 48 evaluation is required.
PBF-t5!5c RcisionO 10r24101 Refcence" NP\5.1.8
. . 2- o0CC5 Point Beach Nuclear Plant SCR 10 CFR 50.59172.48 SCREENUNG (NEW RULE) Veify SCR -anbon allpges
.4 ,..Page5 FUNCTION
'RT VI (72.48) - DETERMINE IF THE CHLANGE INVOLVES A ISFSI LICENSING BASIS &ESIGN
, ALL the questions in Part V are NO, then Part VI is 0 NOT APPLICABLE.)
Compare the proposed activity to the relevam portions of the ISF'1 licensing basis and answer the foUowing questions:
YES NO QUESTION
-ysdems Does the proposed activity involve cask/ISFSI Safety Analyses or plantcaskfISFSI structures,
-d E] E]
components (SSCs) credited in the Safety Analyses?
] I] Does the proposed activity involve plant, cask or ISFSI SSCs that suppor't SSC(s' credited in the Safety Analyses?
El El Does the proposed activity involve plant, cask or ISFSI SSCs whose function is relied upon for pre%ention of a radioactive release, OR whose failure could impact SSC(s) credited in the Safety Analyses?
are
- [] El Does the proposed activity involve cask/ISFSI described SSCs or procedural controls that perform functions that with, regulations, license conditions, CoC conditions, or orders?
required by, or otherwise necessary to compl
[3 El Does the activity involve a method ofevaluation described in the ISFSI licensing basis?
El El Is the activity a test or experiment? (te., a non-passive activity which gathers data)
El El Does the activity exceed or potentially affect a cask design basis limitfor afissionproduct barrier(DBLFPB)?
(NOTE: If THIS questions is answered E a 10 CFR 72.48 Evaluation is required.)
10 CFR 72.48 screening in the If the answers to ALL of these questions are NO, mark Parts VII as not applicable, and document the conclusion section (Part VIII).
"f any of the above questions are marked Y identify below the specific design function(s), method of evaluation(s) or DBLFPB(s) uIved.
EFFECTS (NEI 96-07, PART VII (72.48) - DETERMINE WHETHER THE ACTIVITY INVOLVES ADVERSE Appendix B, Section B.4.2-l)
APPLICABLE.)
(If ALI the questions in Part V or Part VI are answered NO then Part VII is N NOT function. Any YES answer means that a Answer the following questions to determine if the activity has an adverse effect on a design 10 CFR 72.48 Evaluation is required; EXCEPT where noted in Part VIL3.
VI!. 1 Changes to the Facility or Procedmues YES NO QUESTION El El Does thc activity adversely affect the design unction of a plant, cask, or ISFSI SSC credited in safety analyses?
El El Does the activity adversely affect the method of performing orcontrolling the de.ignfunciion of a plant, SSC credited in the safety anal) es?.
cask, or ISFSI NO, describe the basis for the conclusion If any answer is YES, a 10 CFR 72.48 Evaluation is required. If both anmsers are (alttch additional discussion, as necessary):
PnF-1515c Refencr NP5.!.8 Rc*ision 0 l0'2."Ol
_,.eoo L- - L)OCZ..
Point Beach Nuclear Plant SCR *-"L40 .
10 CFR 50.59172.48 SCREENING (NEW RULE) Vcdfy 5CR n ,abc on zl pages C-- o a Page 6 "11.2 Changcs to a Method of Evaluation (If the activity does not involve a method of evaluation, these questions are E] NOT APPLICABLE.)
YES NO QUESTION El El Does the activity use a revised or different method of evaluation for performing safety analyses than that described in a cask SAR?
El l' Does the activity use a revised or different method of evaluation for evaluating SSCs credited in safety analyses than that described in a cask SAR?
If any answer is YES, a 10 CFR 72.48 Evaluation is required. If both answers are NO describe the basis for the conclusion (attach additional discussion, as necessary):
VII.3 Tests or Experiments (If the activity is not a test or experiment, the questions in VIL3.a and VIL3.b are ED NOT APPLICABLE.)
- a. Answer these two questions first:
YES NO QUESTION
[3 E3 Is the proposed test or experiment bounded by other tests or experiments that are described in the cas&
ISFSI licensing basis?
El El Are the SSCs affected by the proposed test or experiment isolated from the cask(s) or ISFSI facility?
If the answer to both questions is NO, continue to VIL3.b. If the answer to EITTHER question is YES, then briefly describe the basis.
above.
- b. Answcr these additional questions ONLY for tests or experiments which do not meet the criteria given in VII.3.a If the ansr%er to either question in VII.3.a is YES, then these three questions are E] NOT APPLICABLE:
YES NO QUESTION El Ml Does the activity utilize or control an SSC in a manner that is outside the reference bounds of the design bases as described in the ISFSI licensing basis?
El El Does the activity utilize or control a plant, cask or ISFSI facility SSC in a manner that is inconsistent Niith the analyses or descriptions in the ISFSI licensing basis?
El E] Does the activity place the cask or ISFSI facility in a condition not previously ev-aluated or that could affect the capability of a plant, cask, or ISFSI SSC to perform its intended functions?
tlhe basis for the Ifanv ansmer in \71I.3.b is YES, a 10 CFR 72.48 Evaluation is required. If the ansvers are all NO, describe conclusion (attach additional discussion as necessary):
PBF-1515ic Rce'een:e" NP 5 1i Rmsion G 10124'01
SCR .- :77 7 Point Beach Nuclear Plant 10 CFR 50.59172.48 SCREENING (NEW RULE) '- SC r,= on 2:l ra*es Jv.'^0-- - -a. Page I
"ART VIII - DOCUMENT THE CONCLUSION OF THE 30 CFR 72.48 SCREENING Check all "ha: apply:
A 10 CFR 72 48 Evaluation is [D required or [E NOT required Obtain a s:-z- :i=zn:ber and pro'i:-'! Lhei .g'lto Rccorcs M1anagemcnrt rcg:adless of the conclusion of the 50.59 or 72.48 screerz:e A VSC-24 cask Safety Analysis Report changee is E) required or Z NOT reqtnrz& UIa \VSC-24 cask SAR P.n,. is rcquircd. then contact the Point Beach Dry Fuel Storag.e group supervisor A Regulatory Commitment (CLB Commitmcnt Database) change is El requrrzd or -Z NOT rmquired If a .eguiato."
Commnentcn Change is required, initiate a commitment change per NP 5.1 7.
A changc to the VSC-24 10 CFR 72.212 Site Evaluation Report is EM requircd or c NOT required Ifa V'SC-2.
J0 CFR 72.212 Site Evaluation Report change is required, then contact the Point ERa:h Dry"Fuel Storage rosupcrvisrr.
1 15 4: 6S 01-I
POINT BEACH NUCLEAR PLANT ARP COI A 1-9 ALARM RESPONSE PROCEDURE MINOR Revision I INSTRUMENT AIR HEADER PRESSURE LOW February 14, 2002 UNIT 0 INITIATING DEVICES AND SETPOINTS INSTRUMENT Annunciator CO0D Window 1-2 Reflash AIR HEADER PRESSURE H+]
LOW TERMINAL STRIP LOCATION UXE-10 1.0 AUTOMATIC ACTIONS None 2.0 POSSIBLE CAUSES 2.1 Alarm on Window 1-2 at rear of panel C01 3.0 OPERATOR ACTIONS 3.1 Perform the following:
3.1.1 IF any AFW pump mini-recirc valve falls shut in conjunction with this alarm, THEN monitor and maintain minimum AFW flow OR stop the affected AFW pump as necessary to control S/G levels.
3.1.2 Respond per ARP C01 D 1-2, INSTRUMENT AIR HEADER PRESS LO.
4.0 SUPPLEMENTAL ACTIONS 4.1 Refer to AOP 5B, Loss of Instrument Air.
5.0 REFERENCES
5.1 Westinghouse drawing 499B666, Sheet 1667; Service/Instrument Air Alarms Main Control Board C01 5.2 ARP C01 D 1-2, INSTRUMENT AIR HEADER PRESS LO 5.3 AOP 5B, Loss of Instrument Air Page I of I REFERENCE USE
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 1 of 33 ° A. PURPOSE
- 1. This procedure provides directions to verify proper response of the automatic protection systems following manual or automatic actuation of a reactor trip or safety injection, assess plant conditions, and direct the operator to the appropriate recovery procedure.
- 2. This procedure is applicable for all plant conditions where RCS hot leg temperature is greater than or equal to 350*F with accumulators in service, and assumes the RHR system is not in service for decay heat removal and all SI system components are available.
B. SYMPTOMS OR ENTRY CONDITIONS if one has not
- 1. The following are symptoms that require a reactor trip.
occurred:
REACTOR TRIP SIGNAL SETPOINT AT Overtemperature Variable AT Overpower Variable RCP Breaker Trip Low Voltage STPT 21.1 RCP Breaker Trip Low Frequency STPT 21.1 RCS Loop Low Flow 93 %
S/G Low-Low Level 25%
S/G Low Level with Flow Mismatch 30% of span PZR Pressure Low 1925 psig PZR Pressure High 2365 psig PZR Level High 80%
NIS Power High Range. High Level 107%
NIS Power Low Range. High Level 20%
NIS Intermediate Range Current equal to 25%
NIS source range 5 X 105 counts/sec Manual Reactor Trip N/A Turbine Trip N/A Safety Injection NIA Safety Injection N/A
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 2 of 33
- 2. The following are symptoms of a reactor trip:
o Any reactor trip annunciator - LIT o Rapid drop in neutron level indicated by nuclear instrumentation o All rod bottom lights - ON o Reactor trip and bypass breakers - OPEN
- 3. The following are symptoms that require a reactor trip and safety injection, if one has not occurred:
SAFETY INJECTION SIGNAL SETPOINT PZR Low Pressure 1735 psig Steam Line Low Pressure 530 psig Containment High Pressure 5 psig Manual Safety Injection N/A
- 4. The following are symptoms of a reactor trip and safety injection:
- a. Safeguards pumps and associated cooling water pumps- RUNNING
"*SI pumps
"* RER pumps
"*Component cooling water pumps
"* Service water pumps
- b. SI-Spray Active Status Panel white lights - ON
- c. Containment Isolation Panels "A' and "B" white lights - ON
- 5. This procedure is entered from the following procedures if SI actuates:
"o EOP-0.2 UNIT 1. NATURAL CIRCULATION COOLDOWN. FOLDOUT "o EOP-0.3 UNIT 1. NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITH RVLIS). FOLDOUT "o EOP-0.4 UNIT 1. NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITHOUT RVLIS).'FOLDOUT
- 6. This procedure is entered from the following procedure when PZR pressure is less than 1735 PSIG:
- EOP-O.1 UNIT 1. REACTOR TRIP RESPONSE. Step 15
- 7. This procedure is entered from The following procedure if PZR level cannot be maintained:
- CSP-I.2 UNIT 1. RESPONSE TO LOW PRESSURIZER LEVEL. Step 7
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 3 of 33
- 8. This procedure is entered from the following procedures if RCS subcooling or PZR level cannot be maintained:
"oEOP-O.1 UNIT 1. REACTOR TRIP RESPONSE. FOLDOUT "oEOP-0.2 UNIT 1. NATURAL CIRCULATION COOLDOWN. FOLDOUT "oEOP-O.3 UNIT 1. NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITH RVLIS). FOLDOUT "o EOP-0.4 UNIT 1. NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITHOUT RVLIS). FOLDOUT
- 9. This procedure is entered from the following procedures when power is restored to a 480 Vac safequards bus prior to placing ECCS components in pull-out:
"oECA-O.O UNIT 1. LOSS OF ALL AC POWER. Step 16 "oECA-O.O UNIT 1. LOSS OF ALL AC POWER. Step 26
- 10. This procedure is entered from other plant procedures when a reactor trip or safety injection has occurred.
C. REFERENCES
- 1. Technical Specifications for Point Beach Nuclear Plant
- 2. Final Safety Analysis Report for Point Beach Nuclear Plant
- 3. As-built plhnt drawings
- 4. Generic Technical Guidelines developed by the Westinghouse Owners Group (WOG). This consists of the following documents:
- a. Low pressure version of the WOG Optimal Recovery Guidelines. Status Trees. and Functional Restoration Guidelines
- b. Background documents for each low pressure version Optimal Recovery Guideline. Status Tree. and Functional Restoration Guideline
- c. WOG Emergency Response Guideline Executive Volume
- d. WOG Emergency Response Guideline Maintenance Program Summary
- 5. Calculation 97-0126, Service Water System LOCA - Recirculation Phase
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 4 of 33 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE Steps 1 through 4 are immediate action steps.
0 Verify Reactor Trip:
- Check reactor trip breakers and Perform the following:
- a. Manually trip reactor.
bypass breakers - OPEN
- b. IF reactor will NOT trip. THEN
"* 1-52/RTA perform the following:
"* 1-52/RTB
"* 1-52/BYA 1) Deenergize rod drive motor "a1-52/BYB generators by deenergizing iB-01 and 1B-02.
"*Check all rod bottom lights - LIT "aIB52-04B or IA52-02
"*Check all rod position indicators "* IB52-05B or 1A52-15
- ON BOTTOM
- 2) WHEN the reactor has tripped.
- Check neutron flux - LOWERING THEN close the following breakers:
"*IN-35
"* IN-36 "*IA52-02 for IB-01
"*IB52-04B for IB-01
"*1A52-15 for IB-02
"* IB52-05B for IB-02
- 3) IF reactor power is greater than or equal to 5% OR intermediate range power is rising. THEN perform the following:
a) Start monitoring Critical Safety Functions per CSP-ST.0 UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to CSP-S.1 UNIT 1.
RESPONSE TO NUCLEAR POWER GENERATION/ATWS.
- 4) As time permits. reenergize stripped MCCs.
- 5) Dispatch operator to locally open reactor trip breakers and bypass breakers in rod control room.
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 SAFETY RELATED EMERGENCY OPERATING PROCEDURE Revision 37 1/10/2002 Page 5 of 33 REACTOR TRIP OR SAFETY INJECTION I RESPONSE NOT OBTAINED I 0STj I ACTION/EXPECTED RESPONSE Verify Turbine Trip:
- a. Check turbine stop valves - BOTH a. Shutdown turbine as follows:
SHUT:
- 1) Depress turbine trip o SL and SR - SHUT pushbutton.
OR 2) IF turbine will NOT trip. THEN perform the following:
o Annunciator IC03 lEl 4-3.
TURBINE STOP VALVES TWO CLOSED a) Manually run back turbine.
- LIT b) Stop both EH oil pumps and OR place in pull-out.
IF turbineTHEN c) tripped. NOT still shuthasmain o Turbine Valves Closed bistable lights - LIT steam isolation valves.
"*1S-2018 for S/G A
"*lMS-2017 for S/G B
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 6 of 33 STE ~ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED ai Verify Safeguards Buses Energized:
- a. Check 4160 Vac safeguards buses a. Try to restore power to at least AT LEAST ONE ENERGIZED one bus:
o 1A-05, train A 1) Close any supply breaker.
o IA-06. train B "o IA52-57 for IA-05 "o IA52-54 for 1A-06 "o IA52-77 for 1A-06
- 2) IF breakers will NOT close.
THEN fast start and load any emergency diesel generator.
- 3) IF power can NOT be restored.
THEN perform the following:
a) Start monitoring Critical Safety Functions for information only per CSP-ST.O UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to ECA-O.0 UNIT 1. LOSS OF ALL AC POWER.
- b. Try to restore power to at least
- b. Check 480 Vac safeguards buses AT LEAST ONE ENERGIZED one bus:
"o 1B-03. train A 1) Close any supply breaker.
"o IB-04. train B "o IA52"58 for IB-03 "o IB52-16B for IB-03 "o IA52-84 for 1B-04 "o IB52-17B for 1B-04
- 2) LF power can NOT be restored.
THEN perform the following:
a) Start monitoring Critical Safety Functions for information only per CSP-ST.O UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to ECA-O.O UNIT 1, LOSS OF ALL AC POWER.
POINT BEACH NUCLEAR PLANT EOP-0 UNIT'1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 7 of 33 LSTEPI ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED I
Check If SI Is Actuated:
- a. Check SI annunciators - ANY LIT a. Determine appropriate recovery actions:
o {IC04-1B 4-2). MANUAL SAFETY 1) Check if SI is required:
INJECTION OR "o Containment pressure GREATER THAN 5 PSIG o {IC04-1B 4-3). CONTAINMENT OR PRESSURE HIGH OR "o Steam line A pressure - LESS THAN 530 PSIG "o (IC04-1B 4-4). PRESSURIZER LOW OR PRESSURE SI "o Steam line B pressure - LESS OR THAN 530 PSIG "o {1C04-1B 4-5). STEAM LINE A OR PRESSURE LOW-LOW OR "o PZR pressure - LESS THAN 1735 PSIG o {1C04-lB 4-61, STEAM LINE B OR PRESSURE LOW-LOW "o PZR level - LESS THAN 10%
OR "oRCS subcooling - LESS THAN 350F
- 2) IF SI is required. THEN perform the following:
a) Manually actuate both trains of SI and Containment Isolation.
b) OBSERVE NOTE PRIOR TO STEP 5 and go to Step 5.
- 3) IF SI is NOT required. THEN perform th-e-folyowing:
a) Start monitoring Critical Safety Functions per CSP-ST.O UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to EOP-0.1 UNIT 1.
REACTOR TRIP RESPONSE.
"*SI pumps BOTH RUNNING
"*RHR pumps - BOTH RUNNING
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 8 of 33 STE IIACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE Foldout page shall be monitored throughout the remainder of this procedure.
5 Verify Automatic Actions Per ATTACHMENT A. AUTOMATIC ACTION VERIFICATION. While Continuing With This Procedure
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/1012002 REACTOR TRIP OR SAFETY INJECTION Page 9 of 33 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION If motor-driven auxiliary feedwater pump flow is greater than 240 gpm. its motor breaker may trip due to over current.
NOTE If both units require AFW flow. at least one AFW pump must be aligned to each unit.
6 Verify Secondary Heat Sink Available:
- a. Check level in at least one S/G - a. Establish AFW flow as follows:
GREATER THAN [51%] 29%
- 1) Manually start pumps and align valves as necessary to establish AFW flow greater than or equal to 200 gpm.
- 2) IF AFW flow greater than or equal to 200 gpm can NOT be established. THEN perform the following:
a) Start monitoring Critical Safety Functions per CSP-ST.O UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to CSP-H.1 UNIT 1.
RESPONSE TO LOSS OF SECONDARY HEAT SINK.
- b. Control pumps and align valves as necessary to maintain S/G level between [51%] 29% and 65%
POINT BEACH NUCLEAR PLANT EOP-0 UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 10 of 33
-.... II .. ... , .. - - - - - - - - - --... I I -. . ....... .... . m~*....... I LJ I ACTION/ (XPECE REPNSE I I LN%.J.L %JM.Lft-L"rLJ 7 Verify RCP Seal Cooling: IF seal cooling to any RCP is lost.
THEN reestablish seal cooling:
o Check labyrinth seal AP GREATER THAN 20 INCHES a. Stop affected RCP(s).
OR o lP-lA. loop A o IP-IB. loop B o Check component cooling to RCP thermal barrier - NORMAL b. Start pumps and align valves as necessary to reestablish component cooling water flow to all RCP thermal barriers.
- c. IF all charging pumps are stopped. THEN reestablish seal injection flow:
- 1) Ensure adequate power is available to run one charging pump. Refer to AOP-22 UNIT 1.
EDG LOAD MANAGEMENT. for XW ratings.
- 2) Start one charging pump at minimum speed for seal injection.
o IP-2A. train A o lP-2B..train A o IP-2C. train B
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 11 of 33
.STE iI ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED I
- 8 Verify RCS Temperature Control: Perform the following:
- temperatures: than 547 0 F AND RCS temperatures *
- are trending lower. THEN *
- follows: *
- AND *
- a) Stop dumping steam.
- STABLE *
- b) IF cooldown continues. THEN *
- control feed flow: *
- 1) Reduce total feed flow.
- 2) Maintain total feed flow *
- greater than or equal to
, 200 gpm until level greater
- than [51%] 29% in at least
- one S/G.
- c) IF cooldown can NOT be stopped
- by controlling feed flow. THEN
, isolate steam lines: *
, 1) Shut both main steam *
, isolation valves. *
,
- lMS-2018 for SIG A *
, . lMS-2017 for SIG B *
- 2) Ensure main steam isolation *
, bypass valves - BOTH SHUT *
, - lMS-234 for S/G A *
- a lMS-236 for S/G B *
- 2. IF RCS cold leg temperature *
, temperature trending higher. THEN *
, stabilize RCS temperature at or *
- below 547°F as follows: *
, o Dump steam to condenser. *
, OR *
- o Dump steam using atmospheric *
, steam dumps.
- POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 12 of 33 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 9 Check PZR PORVs - BOTH SHUT IF PZR pressure less than 2335 psig.
THEN stop PORV flow:
IRC-430 1
IRC-431C 1 a. Manually shut affected PORVs.
- b. IF any PORV can NOT be shut. THEN isolate that PORV:
- 1) Manually shut associated block valve.
"o IRC-515 for IRC-431C "o 1RC-516 for 1RC-430
- 2) I__F ay open PORV can NOT be isolated. THEN perform the following:
a) Start monitoring Critical Safety Functions per CSP-ST.O UNIT 1. CRITICAL SAFETY FUNCTION STATUS TREES.
b) Go to EOP-1 UNIT 1. LOSS OF REACTOR OR SECONDARY COOLANT.
POINT BEACH NUCLEAR PLANT EOP-O UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 13 of 33 I RESPONSE NOT OBTAINED I ACTION/EXPECTED RESPONSE 10 Verify PZR Spray Valves Shut:
- a. Check normal spray valves - BOTH a. IF PZR pressure less than SHUT 2260 psig. THEN stop spray flow:
"* 1RC-431A. loop A 1) Manually shut both spray valves.
"*IRC-431B, loop B
- 2) IF any spray valve can NOT be shut. THEN place manual override switch to close for failed spray valve(s).
"o 1RC-431A-S for 1RC-431A "o 1RC-431B-S for 1RC-431B
- 3) IF_ any spray valve can NOT be shut using manual override.
THEN stop RCP supplying failed spray valve(s).
o For 1RC-431A. stop RCP A o For IRC-431B. stop RCP B
- b. Check auxiliary spray valve b. Stop auxiliary spray flow:
SHUT
- 1) Manually shut auxiliary spray valve.
- ICV-296
- 2) IF auxiliary spray valve can NOT be shut. THEN minimize charging and shut charging line flow control valve.
- IHC-142 11 Check If RCPs Should Remain Running:
- a. Check RCPs - ANY RUNNING a. Go to Step 12.
- b. Check RCS subcooling based on
- b. IF at least one SI pump is core exit thermocouples running AND SI pump capable of GREATER THAN OR EQUAL TO delivering flow. THEN stop both
[600F] 30OF RCPs.
IP-1A.
1 loop A IP-1B. loop B 1
12 Start Monitoring Critical Safety Functions Per CSP-ST.0 UNIT 1.
CRITICAL SAFETY FUNCTION STATUS TREES
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT, EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 Page 14 of 33 REACTOR TRIP OR SAFETY INJECTION I I I ACTION/EXPECTED RESPONSE I I I
RESPONSE NOT OBTAINED I
- 13 Verify Containment Sump *
- Recirculation Not Required: *
- [425 PSIG] 200 PSIG 450 gpm. THEN go to *
, EOP-1.3 UNIT 1. TRANSFER TO
, CONTAINMENT SUMP RECIRCULATION.
14 Check If Secondary System Is Intact: IF any SIG is faulted. THEN go to EOP-2 UNIT 1. FAULTED STEAM No S/G pressure trending lower in GENERATOR ISOLATION.
an uncontrolled manner AND a No S/G completely depressurized 15 Check If S/G Tubes Are Intact: IF conditions indicate a SIG tube rupture. THEN go to EOP-3 UNIT 1,
"*Check secondary system radiation STEAM GENERATOR TUBE RUPTURE.
levels - NORMAL
- a. Condenser air ejector
"*1RE-215
"*RE-225
- b. SIG blowdown
"*IRE-219
"*IRE-222
"*IRE-231 for S/G A
"*IRE-232 for SIG B
"*Request local surveys of main steam lines
"*Request Chemistry to prepare for periodic activity samples of both S/Gs
POINT BEACH NUCLEAR.PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 15 of 33 I ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED I~
16 Check If RCS Is Intact Inside Go to EOP-1 UNIT 1. LOSS OF REACTOR OR SECONDARY COOLANT.
Containment:
- a. Check containment radiation levels - NORMAL
- 1) Containment
"*1RE-102, train A
"*IRE-107. train A
- 2) Containment high range
"*IRE-126. train A
"*1RE-127. train A
"*1RE-128. train A
- b. On 1C20. check containment sump "A" level - NORMAL
"*ILI-958. train A
"* ILI-959. train A
- c. Check containment pressure NORMAL
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-O UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 16 of 33 Io ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED I
- 17 Check If SI Should Be Terminated: *
- a. Check RCS subcooling based on a. Go to Step 18.
- core exit thermocouples - GREATER
- THAN 355F
- b. Verify secondary heat sink: b. -IFneither condition satisfied.
- THEN go to Step 18.
- o Level in at least one S/G
- GREATER THAN 29%
- o Total feed flow to S/Gs *
- GREATER THAN OR EQUAL TO *
- 200 GPM
- c. Check RCS pressure: c. Go to Step 18.
- "*Pressure - GREATER THAN *
- 1600 PSIG *
- AND
- 1
- "*Pressure - STABLE OR TRENDING *
- HIGHER *
- d. Check PZR level - GREATER THAN d. Raise PZR level:
- 10% *
- 1) Raise charging flow.
- 2) Go to Step 18. *
- TERMINATION *
- 18 Stabilize S/G Levels:
- a. Check S/G levels - GREATER THAN a. Maintain total feed flow greater *
- 29% than or equal to 200 gpm until *
- level in at least one S/G is *
- greater than 29%. *
- b. Control feed flow to maintain S/G b. IF level in any S/G continues to *
- levels between 29% and 65% rise in an uncontrolled manner. *
- THEN go to EOP-3 UNIT I, STEAM
- GENERATOR TUBE RUPTURE.
I
POINT BEACH NUCLEAR PLANT POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 17 of 33 RESPONSE NOT OBTAINED ST I ACTION/EXPECTED RESPONSE I 19 Check If S/G Tubes Are Intact: IF conditions indicate a S/G tube rupture. THEN go to EOP-3 UNIT 1.
" Check secondary system radiation STEAM GENERATOR TUBE RUPTURE.
levels - NORMAL
- a. Condenser air ejector
"* IRE-215
"*RE-225
- b. S/G blowdown
"* 1RE-219
"*IRE-222
"*IRE-231 for S/G A
"*1RE-232 for S/G B
"*Request local surveys of main steam lines
"*Request Chemistry to prepare for periodic activity samples of both S/Gs CAUTION If offsite power is lost after SI reset, manual action may be required to restart safeguards equipment.
20 Reset SI 21 Reset Containment Isolation 22 Reset IB-03 And 1B-04 Non-Safeguards Equipment Lockouts
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 18 of 33
[ II ACTION/EXPECTED RESPONSE I i I
RESPONSE NOT OBTAINED I CAUTION Placing loads on energized AC safeguards buses in excess of the power source's capacity could result in loss of the power source. Refer to AOP-22 UNIT 1. EDG LOAD MANAGEMENT, for KW ratings.
Check 4160 Vac Safeguards Buses - Monitor EDG loading per *
, while continuing with this *
- lA-05.
I train A procedure.
- lA-06.
1 train B 24 Reestablish Instrument Air To Containment:
- a. Start second instrument air compressor "oK-2A "o K-2B
- b. Check instrument air header b. Start service air compressors as pressure - GREATER THAN 80 PSIG necessary to establish instrument air header pressure greater than 80 psig.
"oK-3A "oK-3B
- c. Open one and then open the other c. IF no valve can be opened. THEN gag open one valve as follows:
instrument air containment isolation valve
- 1) Manually hold valve switch in
"*lIA-3047 open position.
"*lIA-3048
- 2) Locally gag open valve.
POINT BEACH NUCLEAR PLANT, EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 111012002 REACTOR TRIP OR SAFETY INJECTION Page 19 of 33 IACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED I 25 Check If RCS Is Intact Outside Perform the following:
Containment:
- 1. Evaluate cause of abnormal conditions.
- a. Request local radiation surveys in auxiliary building
- 2. IF cause is a loss of RCS inventory outside containment.
- b. Check auxiliary building THEN go to ECA-1.2 UNIT 1. LOCA radiation levels - NORMAL OUTSIDE CONTAINMENT.
"*PPCS RMS screen. Page 104
"( New PPCS RMS GRID screen)
"*Local surveys
- c. Check auxiliary building sump levels - NORMAL
"*COlA 1-11. AUXILIARY BUILDING
-19 FT SUMP LEVEL HI - NOT LIT
"*COlA 2-11. AUXILIARY BUILDING NORTH SUMP LEVEL HI - NOT LIT
"*COlA 3-11. AUXILIARY BUILDING SOUTH SUMP LEVEL HI - NOT LIT 26 Check PZR Relief Tank Conditions Evaluate cause of abnormal conditions.
NORMAL
- Pressure a Temperature
- Level 27 Check If RHR Pumps Should Be Stopped:
- a. Go to EOP-1 UNIT 1. LOSS OF
200 PSIG
- b. Go to Step 28.
- c. Stop both RER pumps
"* 1P-1OA. train A
" IP-10B, train B
- than 200 psig uncontrolled manner to less than
, 200 psig. THEN restart RHR pumps
- to supply water to RCS.
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 20 of 33 I I I ACTION/EXPECTED RESPONSE I I l
RESPONSE NOT OBTAINED 28 Verify Charging Flow:
- a. Ensure RCS Loop A Cold Leg Normal Charging Isolation Valve - OPEN a ICV-1298
- b. Check charging pumps - AT LEAST b. Perform the following:
ONE RUNNING
- 1) IF component cooling water "o lP-2A. train A flow to any RCP thermal "o lP-2B. train A barrier is lost. THEN locally "o 1P-2C. train B shut affected RCP(s) seal injection throttle valve before starting charging pumps.
o ICV-300A, RCP A o ICV-300B. RCP B
- 2) Start charging pumps as necessary to establish at least one running.
- c. Start additional charging pumps and adjust speed on running charging pumps as necessary to establish desired charging flow
- d. Adjust charging line flow controller as necessary to maintain labyrinth seal &P greater than 20 inches
- 1HC-142 29 Check If Diesels Should Be Stopped:
- a. Restore offsite power to 4160 Vac
- a. Check 4160 Vac safeguards buses safeguards buses.
ENERGIZED BY OFFSITE POWER
"* 1A-05. train A
"*1A-06. train B
- b. Stop all unloaded EDGs:
"o OP-11A G-01. EMERGENCY DIESEL GENERATOR G-01 "o OP-11A G-02. EMERGENCY DIESEL GENERATOR G-02 "o OP-llB. EMERGENCY DIESEL GENERATOR G-03 (G-04)
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 21 of 33 LszpI ACTION/EXPECTED RESPONSE I I
I I
RESPONSE NOT OBTAINED I 30 Ensure Miscellaneous Electrical Loads Are Energized:
- a. Ensure MCCs - ENERGIZED
"*1B-31. 1B52-14C. train A
"*B-43. 1B52-21C. train B
- b. Check battery chargers supplying b. Restore battery chargers:
DC buses - ENERGIZED
- 1) Close affected battery charger o D-07 supply contactor.
o D-09
- 2) IF contactor does _NOT close OR o D-108 battery charger will NOT o D-109 operate. THEN restore battery chargers per AOP-O.O, VITAL DC SYSTEM MALFUNCTION. while continuing with this procedure.
- c. Ensure cavity cooling fan - ONE RUNNING "o IW-4A. train A "o IW-4B. train A
- d. Check cable spreading room d. Restore cable spreading room ventilation per 01-90. CONTROL.
ventilation operating: AND CABLE SPREADING COMPUTER.
ROOM VENTILATION SYSTEMS.
- 1) Check cable spreading room recirc fans 7 ONE RUNNING "o W-13A1 "o W-13A2
- 2) Check CSR chilled water recirc pumps - ONE RUNNING "oP-1lIA "oP-111B
- e. Start additional loads as necessary to meet current plant conditions. Refer to AOP-22 UNIT 1. EDG LOAD MANAGEMENT 31 Return To Step 8
-END-
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 22 of 33 STE ACTION/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED ATTACHMENT A (Page 1 of 10)
AUTOMATIC ACTION VERIFICATION Al Verify Feedwater Isolation:
- a. Check main feed lines isolated: a. IF any main feedline can NOT be isolateed. THEN perform the
- 1) Feedwater regulating control follow:Lng:
valves - BOTH SHUT a) Tri p main feed pumps.
" 1CS-466 for S/G A
"* ICS-476 for SIG B 1 1]P-28A
- 1)P-28B
- 2) Feedwater regulating bypass valves - BOTH SHUT b) Pla,ce condensate pumps in pull1-out.
"*1CS-480 for S/G A P-25A
"*1CS-481 for S/G B I
- P-25B c) Sto p heater drain tank pumps.
P-27A P-27B P-27C
- b. Check main feed pumps - BOTH b. Trip main feed pumps.
TRIPPED
"*1P-28A
"*1P-28B
SHUT
"*1CS-2190. train A
" ICS-2189. train B
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 23 of 33 STEP I ACTION/EXPECTED RESPONSE I RESPONSE NOT OBTAINED I ATTACHMENT A (Page 2 of 10)
AUTOMATIC ACTION VERIFICATION A2 Verify Containment Isolation:
- a. Check containment isolation a. Perfor2n the following:
panels "A" and "B" - ALL LIGHTS LIT 1) Man ually actuate Containment Isolation.
- 2) IF any valve open AND flow path NOT required. THEN shut valve(s). Refer to ATTACHMENT B.
- b. Manually shut valve(s).
- b. Check other valves - SHUT a RS-SA-9 . Unit 1 steam supply to rad waste system Any valve which may be open under administrative control A3 Verify AFW Actuation:
BOTH RUNNING
- 1) Ensure steam supply valves to
"*P-38A. train A turbine-driven AFW pump - BOTH
"* P-38B. train B OPEN
"* IMS-2020. train A
"* lMS-2019. train B
- 2) WHEN SI sequence complete.
THEN manually start motor-driven AFW pumps.
- b. Check S/G levels - BOTH LESS THAN b. Go to Step A4.
[51%] 25%
- c. Ensure steam supply valves to turbine-driven AFW pump - BOTH OPEN lMS-2020.
I train A 1MS-2019.
l train B
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 24 of 33 rnS i _
ACTI O1/EXPECTED RESPONSE I I RESPONSE NOT OBTAINED ATTACHMENT A (Page 3 of 10)
AUTOMATIC ACTION VERIFICATION A4 Check SI Pumps BOTH RUNNING WHEN SI sequence complete. THEN establish SI flow as follows:
"*IP-15A. train A
" IP-15B. train B a. Manually start SI pumps.
- b. IF any SI pump can NOT be started. THEN isolate system boundary as follows:
i) Place affected SI pump in pull-out.
- 2) Ensure affected SI pump suction valve shut.
"o ISI-896A. train A "o LSI-896B. train B Check RHR Pumps - BOTH RUNNING WHEN SI sequence complete. THEN A5 establish RHR flow as follows:
"*IP-IA. train A
" IP-10B. train B a. Manually start RHR pumps.
- b. IF any RHR pump can NOT be started. THEN isolate system boundary as follows:
- 1) Place affected RHR pump in pull-out.
- 2) Ensure affected RER pump suction valve shut.
"o 1SI-856A. train A "o ISI-856B. train B
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 25 of 33 Thj IACT ION/EXPECTED PRESPONSE 1 I I RESPONSE NOT OBTAINED I ATTACHMENT A (Page 4 of 10)
AUTOMATIC ACTION VERIFICATION A6 Check Component Cooling Water Pumps Establish one component cooling water pump running as follows:
- ONLY ONE RUNNING
- a. IF no component cooling water "o IP-IA, train A pump running. THEN perform the "o IP-IIB. train B following:
- 1) Stop all RCP(s).
"* IP-IA. loop A
"* IP-IB. loop B
- 2) Manually start one component cooling water pump by placing control switch to stop and then auto-after-stop.
- 3) Match flags for running and stopped pumps.
- b. IF both component cooling water pumps running, THEN place one pump in standby.
POINT BEACH NUCLEAR PLANT EOP-0 UNIT I EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 26 of 33
_. ,I I I II RESPONSE NOT OBTAINED II L TEJI ACTION/EXPECTED RESPONSE I ATTACHMENT A (Page 5 of 10)
AUTOMATIC ACTION VERIFICATION A7 Verify Service Water System Alignment:
- a. WHEN SI sequence complete. THEN
- a. Check service water pumps - SIX manually start pumps.
RUNNING S P-32A. train A P-32B. train A 6 P-32F. train A a P-32C. train B 0 P-32D. train B S P-32E. train B
- b. Perform the following:
- b. Check service water isolation valves - SHUT
- 1) Manually shut valve(s).
a At least one spent fuel pool
- 2) _F any isolation valve will heat exchanger A isolation NOV NOT shut. THEN locally shut valve or associated manual "o SW-2927A. inlet NOV isolation valve.
"o SW-2930A. discharge NOV
- At least one spent fuel pool heat exchanger B isolation MOV "o SW-2927B. inlet NOV "o SW-2930B. discharge NOV
"*At least one auxiliary building A/C condenser isolation MOV "o SW-2816. train A "o SW-4479. train B
"*At least one water treatment system inlet NOV "oSW-4478. train A "oSW-2817. train B
- c. Locally at blowdown evap panel c. Perform the following:
C-180. check at least one
- 1) Locally shut valve(s).
radwaste service water valve shut train A 2) IF any valve will NOT shut.
"o SW-LW-61. THEN locally shut associated "o SW-LW-62. train B manual isolation valve.
I
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 27 of 33 LsmP I ACTION/EXPECTED RESPONSE I I I
RESPONSE NOT OBTAINED I ATTACHMENT A (Page 6 of 10)
AUTOMATIC ACTION VERIFICATION A8 Verify Containment Accident Cooling Units Running:
- a. Check containment accident a. WHEN SI sequence complete. THEN recirculation fans - ALL RUNNING manually start fans.
"*1W-lAl. train A
"*IW-IBI. train A
"*IW-ICI. train B
"*IW-lDI. train B
- b. Check containment ventilation b. Manually open containment cooler outlet emergency FCVs ventilation cooler outlet BOTH OPEN emergency FCVs.
"* ISW-2907. train A
"* ISW-2908. train B
- c. Check annunciator COIB 2-3. c. Perform the following:
UNIT 1 CONTAINMENT RECIRC COOLERS
-WATER'FLOW LOW - CLEAR 1) Ensure non-affected unit's service water isolation valves
- BOTH SHUT
- 2SW-2907 train A
- 2SW-2908 . train B
- 2) Isolate service water to non-safety loads as necessary to clear annunciator.
A9 Check Control Room Fans Armed:
- a. Check Control Room Charcoal a. At MCC 1B-32. depress Control Circuit Arming pushbutton for Filter Fan W-14A - WHITE LIGHT OFF Control Room charcoal filter fan W-14A.
a IB52-329B
- b. Check Control Room Recirc Fan b. At MCC 1B-42. depress Control W-13B2 - WHITE LIGHT OFF Circuit Arming pushbutton for Control Room'recirc fan W-13B2.
a IB52-428M
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1110/2002 REACTOR TRIP OR SAFETY INJECTION Page 28 of 33 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED ATTACHMENT A (Page 7 of 10)
AUTOMATIC ACTION VERIFICATION A10 Check Control Room Ventilation - IN Align Control Room ventilation per AN ACCIDENT MODE 01-90. CONTROL. COMPUTER. AND CABLE SPREADING ROOM VENTILATION SYSTEMS.
"*Control Room recirc fans - AT LEAST ONE RUNNING "oW-13BI "o W-13B2
"*Control Room damper solenoid valve
- PURPLE LIGHT LIT All Check If Main Steam Lines Can Remain Open:
- a. Check MSIVs - ANY OPEN a. Go to Step A12.
- b. Check containment pressure - LESS b. Isolate both steam lines as THAN OR EQUAL TO 15 PSIG follows:
- 1) Shut both main steam isolation valves.
"*1MS-2018 for S/G A
"*lNS-2017 for SIG B
- 2) Go to Step A12.
- c. Check high-high steam flow c. Ensure main steam isolation valve bistable lights - NOT LIT on affected main steam line(s) shut.
o 1MS-2018 for SIG A o IMS-2017 for S/G B
- d. Check high steam flow bistable d. IF RCS average temperature is lights - NOT LIT less than 543'F. THEN ensure main steam isolation valve on affected main steam line(s) shut.
o IMS-2018 for S/G A o lMS-2017 for SIG B
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1110/2002 REACTOR TRIP OR SAFETY INJECTION Page 29 of 33 ATTACHMENT A (Page 8 of 10)
AUTOMATIC ACTION VERIFICATION A12 Verify Proper SI Valve Alignment: Manually align pumps and valves as necessary to establish proper SI
- a. Check Unit 1 SI Active status alignment.
panel - ALL LIGHTS LIT
- b. Check Unit 1 SI - Spray Ready status panel - NO LIGHTS LIT
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/1012002 REACTOR TRIP -OR SAFETY INJECTION Page 30 of 33 ACTION/EXPECTED RESPONSE IRESPONSE I
NOT OBTAINEDI I ATTACHMENT A (Page 9 of 10)
AUTOMATIC ACTION VERIFICATION
- A13 Verify Containment Spray Not Establish containment spray as ,
Required: follows:
- a. Check containment pressure 1. Check containment spray actuated: *
- recorder HAS REMAINED LESS THAN *
- 25 PSIG
- Annunciator {Co0 B 2-6). *
, CONTAINMENT SPRAY - LIT *
- a 1PR-968 *
- IPR-969 1 2. IF containment spray has NOT
, actuated. THEN manually actuate *
, containment spray. *
, 3. Verify the following equipment
, status: *
, a) Ensure containment spray pump *
, discharge MOVs - ALL OPEN *
, e ISI-860B for IP-14A *
, e 1SI-860C for lP-14B *
,
- 1SI-860D for lP-14B *
, b) Ensure containment spray pumps
, - AT LEAST ONE RUNNING *
, o IP-A. train A*
, o IP-14B. train B *
- c) Shutdown one train of *
, containment spray as follows:
, 1) Place one containment spray *
- pump in pull-out. *
, o lP-14A. train A
- o lP-14B. train B
, 2) Ensure suction on idle
, spray pump shut.
- o ISI-870A for 1P-14A
, d) WHEN containment spray has
, been actuated for greater than *
, two minutes. THEN ensure at *
, least one spray additive *
, eductor suction valve open. *
,o ISI-836A. train A
, o ISI-836B. train B
- POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 31 of 33 I I RESPONSE NOT OBTAINED TE ACTION/EXPECTED RESPONSE I I I ATTACHMENT A (Page 10 of 10)
AUTOMATIC ACTION VERIFICATION A14 Verify SI Flow:
- b. Check SI pumps - FLOW INDICATED b. Manually start pumps and align valves as necessary to establish SI pump flow.
"a lFI-925. train A
"* lFI-924. train B
- c. Check RCS wide range pressure c. Return -o procedure and step in LESS THAN [425 PSIG] 200 PSIG effect.
- d. Check RHR pumps - FLOW INDICATED d. Manually start pumps and align valves as necessary to establish
"* IFI-626. train A RER pump flow.
"* IFI-928. train B
-END-
EOP-0 UNIT 1 POINT BEACH NUCLEAR PLANT SAFETY RELATED EMERGENCY OPERATING PROCEDURE 1/10/2002 Revision 37 Page 32 of 33 REACTOR TRIP OR SAFETY INJECTION
- ATTACHMENT B (Page 1 of 2)
CONTAINMENT ISOLATION VALVES PANEL A COMPONENT DESCRIPTION TRAIN Auxiliary charging line A 1CV-1296 Pressurizer relief tank to gas analyzer A 1RC-538 A
1WG-1788 Reactor coolant drain tank to gas analyzer A
IWL-1698 Reactor coolant drain tank to -19 ft sump A
1WL-1003A Reactor coolant drain tank pump suction A
IWL-1003B Reactor coolant drain tank pump suction A or B 1RC-508 Reactor makeup water to containment B
1RC-539 Pressurizer relief tank to gas analyzer B
1WG-1789 Reactor coolant drain tank to gas analyzer A or B 1SI-846 Accumulator nitrogen supply B
1WL-1721 Reactor coolant drain tank pumps suction Containment purge supply A IVNPSE-3244 Containment purge exhaust r A A
IVNPSE-3212 Sump A drain A IWL-1723 A
1SC-951 Pressurizer steam sample I r Pressurizer liquid sample A ISC-953 B
1VNPSE-3245 Containment purge supply B
1VNPSE-3213 Containment purge exhaust B
IWL-1728 Sump A drain A or B 1SC-966A Pressurizer steam sample A or B 1SC-966B Pressurizer liquid sample
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 1 POINT BEACH NUCLEAR PLANT SAFETY RELATED EMERGENCY OPERATING PROCEDURE Revision 37 1/10/2002 Page 33 of 33 REACTOR TRIP OR SAFETY INJECTION ATTACHMENT B (Page 2 of 2)
CONTAINMENT ISOLATION VALVES PANEL B COMPONENT DESCRIPTION TRAIN 1CC-769 Component cooling water outlet from excess A or B letdown heat exchanger Reactor coolant pump seal return A 1CV-313 Letdown line A lCV-371 Steam generator blowdown A or B lMS-5958 Steam generator blowdown A or B lMS-5959 Reactor coolant drain tank vent A IWG-1786 Reactor coolant pump seal return B 1CV-313A Letdown line B 1CV-371A Reactor coolant drain tank vent B LWG-1787 RE-211/212 supply A IRM-3200C RE-211/212 return A or B 1RM-3200A Steam generator A sample A or B lMS-2083 Steam generator B sample A or B lMS-2084 Reactqr coolant hot leg sample A 1SC-955 Instrument air line A or B IIA-3047 RE-211/212 supply B 1RM-3200B I t A or B 1SC-966C Reactor coolant hot leg sample I
I.- - I A or B lIA-3048 Instrument air line I
-END-
FOLDOUT PAGE FOR EOP-0 UNIT 1
- RCS subcooling - LESS THAN (601F] 30OF FLOW
- SI pumps - AT LEAST ONE RUNNING AND CAPABLE OF DELIVERING
- Operator controlled cooldown .- NOT IN PROGRESS
- 2. FAULTED S/G ISOLATION CRITERIA manner OR any S/G IF any S/G pressure trending lower in an uncontrolled completely depressurized. THEN the following may be performed:
- a. Isolate feed flow to faulted S/G.
gpm until
- b. Maintain total feed flow greater than or equal to 200 narrow range level in at least one S/G is greater than [51%] 29%.
- 3. RUPTURED S/G ISOLATION CRITERIA S/G has IF any S/G level rises in an uncontrolled manner OR any range level in affected S/G(s) is abnormal radiation. AND narrow feed flow may be isolated to affected greater than [51%] 29%. THEN S/G(s).
- 4. AFW SUPPLY SWITCHOVER CRITERIA AFW IF CST level lowers to less than 8 feet. THEN switch to alternate ESTABLISHING ALTERNATE AFW SUCTION suction supply per AOP-23 UNIT 1.
SUPPLY.
- 5. ADVERSE CONTAINMENT CONDITIONS setpolnt IF any condition listed below occurs. THEN adverse containment values in brackets. []. shall be used:
o Containment pressure - GREATER THAN 10 PSIG OR 10' R/HR o Containment radiation level - GREATER THAN OR EQUAL TO r OR o Integrated dose to containment - GREATER THAN 10' R
- 6. AFW NINIMUM FLOW REQUIREMENTS COI A 1-9.
IF any AFW pump mini-recirc valve fails shut OR annunciatorand maintain INSTRUMENT AIR HEADER PRESSURE LOW in alarm. THEN monitor to control minimum AFW flow or stop the affected AFW pump as necessary S/G levels.
o P-38A minimum flow - GREATER THAN 50 GPM o 'P-38B minimum flow - GREATER THAN 50 GPM o P-29 minimum flow - GREATER THAN 75 GPM
Nuclear Power Business Unit A TEMPORARY CHANGE REVIEW AND APPROVAL Note Refer to NP 1 2 3, Temporary ProccdureChanges.forrequirements Page I of , .
I - INITIATION Doc Number EOP-0 CurrentRev 36 Unit PB2 TempChangeNo. 2 pft _ 79g72_
Document Title REACTOR TRIP OR SAFETY INJECTION Existing Effective Temporary Changes Brief Description ADDED FOP ITEM TO ADDRESS AFV MINDIMUM FLOW (Identify specific changes on Form PBF-O026:, Domimen Revic% and Aproval Continuation. and vnclud-: with the package) 0 Initiate PBF-0026h and include with thle change.
Other documents required to be effecti% concurrently with tie temporary change. NONE Changes pre-screened according to NP 10.3.17? 0 NO [I YES (IfY. .hstrrzerr and .raveaor PBF-0:/ft to.?13 1)
Screening completed according to NP 10.3.1? El NA Z YES Safety E- aluation Required? F NO El YES awi.- r, ... ,-,a, e -,S el*ra c bo-, ,onin Dctermine if the change constitutes a Change Of Intent to the procedure by evaluating t'.e following questions (If anr ansem a:xc'ES, a revision mzy be processed o- final re,6ev.s and approvals shall be obaincd before implemenming) d Will the proposed change: YES NO I. Require a change to, affect or invalidate a requirement, commitment, edalation or de.cription in the Current Licensing Basis (as defined in NP 10 3.1)?
- 2. Cause an increase in magnitude, significance or impact such that it should be processed as a revision?
- 3. Delete or modify a prerequisite, initial condition, precaution, limitation or other steps that cuuld have safety significance or aftect the procedure's margin of safety?
- 4. Delete QC hold points, Independent Verification or Concurrent Check steps w*ithout the related step(s) :hat require the performance also being deleted? El ED
- 5. Change Tech Spec or other regulatory acceptance criteria other than for re-baselining z purposes?
- 6. Require a change to the procedure Purpose or change the procedure classification? El 0 Initiated By (pint.sin) ! ' Date .. ,/
II - INITIAL APPROVAL .- "
This change is correct and compIcte, can be performed as vritten, and does not j*"rsely affec .personmei or nuclear safety, or Plant operating conditions. /
Group Supernisor (prinL'sign) 27V,, f.< , =, / , ýAz - Date/
(Cannot be the Initiator)
-Thischange does not adversely affect Plant operating conditions. (Saf.ty Rel--ed procedures onl))
SeniorReactorOperator (i.,'si) _ Date (Cannot be the Initiator or Group upe isor)
II1 - PROCEDURE OWNER REVIEW I Permanent 0l One-time Use 0] Expiration Date, Event or Conchdtion:
El Hold change until procedure completed (final review and approval -'qtir*,*ithin 14 days of initial appr al)t 0] QR/IMSS Revicw NOT Required (AdninN.SR: an!) ), QR Review e r !SS i.' Required 6r-:
5)
Procedure Owner (prirntsign) /Date 4 1, Thi C"ane and -.urnortino reaut')*'ns '*rr'rectjv eo p'e!ted and crocess-ed I '- I (Must be completed "ithln 14 dj.s ofinitia! approaI)
IV - FINAL REVIEW AND APPROVAL
('he Initiator, QR and Approal Authont% shaIne Independent from each other)
<WMISS (prir i-ign) r'- AZ M , I Date t
Indicates 50 59/72.48 aphlicabditit ansctwil a,' neccs-ar szrerningsea.uaciPcrformed, dedtcr,-rina zcn made as to %;hethe alditonal cro-s-disciplnary rc*ie, iequired. and ifrcquned, pnformedC MSS Meeting No ~_ _ _ _
Appro, al Authority (print'sign) *J) 7* .i5, J . Date V- REVISION INFORMATION FOR PF-RMANENT 0 A .fGES Post T~vi tiPRe%icw(p,-t (prin.t.,...->
g) / Date 7 2-Tz Indicates tcmporary Ihangcd) z; orpralcJe,-ti)'a 'pro ndandno c.ge( o d^ DE C Incorporated into Rexision Number 37 Effectixe Date [C ] 4 200!
REG'D DEC 17 ZOO0 123
It DEC 1 4 2o0i Point Beach Nuclear Plant DOCUMENT REVIEW AND APPROVAL CONTLN-UATION Pagze 2- of 21/2L Doc Number EOP-0 Revision 36 Umit Tide REACTOR TRIP OR SAFETY INJECTION Temporary Change -Number o 1- o g';, 2 Description of Changes:
Step
- ChangelReason CHANGE: Added AFW minimum flow requirements for the AFWV pumps REASON: To prevent damage to the AFW pumps on a loss of insrument air due to the AFW pump mini-recirc valve failing shut with minimum flow through the pump is less than required to cool the FOP pump.
C 4-Ir: .
L-Izj-:--ý!
Other Comments U4"t
- Note: Rcording ofStep Na rnberts) is not recuired f L ocurrTences of idenical inform.ation cr ".h'en not bencriial to reCic, Cr.
SPF-OZ:6c Rciision6 C4:1S.01 Rdrfncns N? I : 3 NP 12 3
- 0 2
t Point Beach Nuclear Plant TEMPORARY CHANGE AFFECTED ML4ANUAL LOCATION Page '__ I of %_(
Procedure Number EOP-0 Revision 3G Lnit PB2 Title REACTOR TRIP OR SAFETY NWJECTION Temporary Change Number o -
I - IMMEDIATELY AFTER INITIAL APPROVA\L ON PBF-0026e (Non-Lntent ch-ages)
(after Final ApProa] if chan-e of intent inolh ed)
This procedure change has been processed as follows: (Manual/Location) I Date Performed El Copy included in work package for field implementation. (WO No ) I
[]
[
Copy filed in Control Room temp change binder (Operations only).
Original change package provided to I ', 6 a 5 9-c., to obtain Procedure Owner Review (e.g. Ownerrview may becoordinated by la-GroupOAIl, Procedure Writer. Procceure Supervisor, eie i'
1it- /
[]
Performed By (print and sign) Date A II - PROCEDURE OWNER REVIEW ON PBF-0026e (may be performed by OA IL Procedure Writer, etc.)
This procedure change has been processed as follows: (ManualLfocation) I Performed PDate W Copy sent to Document Control Distribution Lead for Master File. /.5-of C\ot requ~red for one-time use change)
[] Copy filed in Group satellite file. (Not required for one-time use changes) I El Copy filed in Group one-time use file.
S Original Temp Change provided to DOlS _to obtain Final Appro%als It (eg. fiwal ar-vaI maybe coorduiatedby In-Group OA II. Procedure NVri:er. Procedure Supe-risc-. etc) t: b I
I-4t Performcd By (print and sign) .:.,.. *(t.l! Z. '/ Date*
3'"
PBr-0026h Reatsion5 06 !3:01 RZcfcrc'-.ze \11 1 2 3
Point Beach N.iuclcar Plant SCR ,_____-_ _,
- 'I.,.SCR - on ail paps 10 CFR 50.59172.48 SCREENING (NEW RULE) Page 1
-)f Proposed Activity: Unit I EOP Rev. 35. Unit 2 EOP Rev..36. Unit I EOP-') 1. Rev 24 Unit 2 EOP-0 I - Rev 23 CR 01-227S Action 2 ASsociated Reference(s) #::
Prepared by- Bob Warteniberg Dat: /.66 Name (Pnnt) - S,'natre Graves NaverClayton n Date./
RvdNcbName (Print) / 6atue THE PLANT AND ISFSI LICENSING PART I (50.59/72.4S) - DESCRIBE THE PROPOSED ACTIVITY AND SEARCH BASIS (Resource Manual 5.3.1)
N-EI 96-07. Appendix B. Guidelines for NOTE: The "NMNIC 10 CFR 50.59 Resource Manual" (Resource Manual) and 10 CFR 72.48 Implementation should be used for guidance to determine the proper responses for 10 CFR -50.59 and 10 CFR 72.48 screenings.
(The 10 CFR 50.59 / 72 48 1.1 Describe the proposed actidvity and the scope of the activity being co%ered b. this screening.
via the'applicability and pre-screening process review of other portions of the proposed activity may be documented requirements in NP 5.1.8.) Appropriate descriptive material maybe attached.
I. The foldout page item, "AF-W Minimum A foleout-page item is being added to Units 1 & 2 procedures EOP-O and EOP-0.
AFW pumps in the case of a failed closed rrnni-recirc Flow Requirements", shall address minimum flow required by the valve on any running AFW pumps.
sis Repcrt ('SAR), FSAR Change Requests 1.2 Search the PBNP Current Licensing Basis (CLB) as follo%%s: Final Safety Aaab (FCRs) wvith assigned numbers, the Fire Protection Evaluation Report (FPER), the CLB (Regulatory) Commitment Database, and Improved), the Techmical Specifications Bases, and the Technical the Technical Specifications (both Custom the ISFSI licensing basii as follows: VSC-24 Safety An-alysis Report. the VSC-24 Certificate Reqtuirements Manual. Search 10 CFR 72.212 Site Evaluation Report.
o.f Compliance, the CLB (Regulatory) Commitment Database, and the VSC-24 and methods of evaluation for both the plant and for the Describe the pertinent design function(s), performance requirements, information is described in the above documents (by document caskfISFSI as appropriate. Identify where the pertinent Manual 5.3.1 and NET 96-07, App. B, B.2) section number and title). (Resource tSAR 10.2, Auxiliary Feedwater System Technical Specification (ITS)? Changes to 1.3 Does the proposed activity involve a change to any Custom or Improved 5.3.1.2).
Technical Specifications require a Licens= Amendment Request (Resource Manvual Section El Yes 0 \No Technical Specification Change:
be ard it is required.
h.,hy If a Technical Specification change is required, explain -,hat the change should or specificatiors incorpomted in any VSC-24 cask 1.4 Dces the proposed activity involve a change to !he terms, cornditions of Coa-plicnce require a CoC amendment request Certificate of Compliance (CoC)? Changes to a VSC-24 cask Certificate
[] Yes 0 No
%%hatthe change should be and %Nhyit is required.
If a storage cask Certificate of Compliance change is required. e"plain PBr-i5tlSc Reft-ic- N? 5 Revislon 0 r.-4'01
Point Beach Nuclear Plant 5CR 6 I2c-sc. en 0OTy' 7 10 CFR 50.59/72.48 SCREENING (NEW RULE) Vonall Page 2 2ags il CFR 50.59 SCREENIN G ---------------------------------------------------
tVesource Manual 53 2)
PART 11 (50.59) - DETER.MNE IF THE CHANGE INVOLVTES A DESIGN FUVCTION Compare the proposed activity to the reievt'nt CLB descriptions, and answer the following questions:
YES .NO QUESTION credie.t in the 0 E Does the proposed activity involhe Safety Analyses or structures, systems and components (SSCs)
Safety Analyses?
[ Docs thc proposed activity involve SSCs that support SSC(s) credited in the Safety Anal;.ses?
C< 1 Does the proposed activity invoh,e SSCs v, hose failure could initiate a transient (e g, reactor trip. loss of feed.ater, etc.) or accident, OR -,%hose failure could impact SSC(s) credited in the Sdfety Anal%ses?
'.- [ Does the proposed activity invol%e CLB-described SSCs or procedural controls that perform functions =at are required by, or othenrise necessary to comply with, regulations, license conditions, orders or technical specifications?
l [] Does the activity involve a .methodofeicluation described in the FSAR?
[] [] Is the activity a test or experiment? (i e., a non-passi, e activity which gathers data)
] [] Does the activity exceed or potentially affect a design basis limitfo* -'fissionproduct barrier(DBLFPB,?
(NOTE: IfTHIS questions is answ.ered YES, a 10 CFR 50.59 Evaluation is required.)
screening in the Ui the a,"s%%ers to ALL of these questions are NO. mtrk Part III as not applicable, document the 1" CFR 50.59 clusion section (Part IV), then proceed direcdy to Part V - 10 C-rR 72.48 Pre-screening Questions evaluation(s) or DBLFFB(s) uI any of the above questions are marked YES, identify below the specific design function(s). method of involved minimum flow to dissipate heat. This FSAR 10.2 states each AFW pump has an AOV controlled recirc line back to the CST to ensure running AFW pump in the case of a failed shut AFW change ensures the mn*rimum AFW flow requirements will be maintained on any
- mini-recirc flow control valve.
(Resource Manual 5.3.3)
PART 111 (50.59) - DETERMINE WHETHER TIlE ACTIVITY IN"VOLVES ADVERSE EFFECTS If ALL the questions in Part II are answered NO. then Part III is El NOT APPLICABLE.
a desigr 'frct-on. Any YES ans-wer means that a
-Answer the following questions to determine if the activity has an adve-se effect on 10 CFR 50 59 Ealultion is required; EXCEPT %,where noted in Part 111.3.
Ill. 1 CHA-NGES TO THE FACILITf OR PROCEDURES YES .NO QUESTION Docs the activiy ad- ersely affect the des-gn funcrion of an SSC c.edited in re-anal %ses?
El 0 of an SSC El 0 Does the activit.y ad%erszly affect the method of performing or controlling the designrfunc6on credited in the safety anal'sses?
a:-e N.O. describe the basis for the conclusion 1 If any ans-,er is YES, a 10 CFR 50.59 Evaluation is required. If both answers (attach additional discussion as necessary) 1 2 are not violated.
Th1is change ensures that minimum recirc ilo*,, requirements as sated in FS.AR PBF.1515c Ref. e"nz¢- N? " I S Rcvsion 0 10r24:01
.... aw.,-rnnr.rrnr.rr.fa ..
- j.. 4'r
Point B.ch Nuclear Plant SCR *C0 O-10 CFR 50.59/72.48 SCREENI.NG (.NEW RULE) v.-.: SCR n all p--.-s Page 3 2 CHANGES TO A NIETHOD OF EVALUATION (If the ac.i; iv' does not in-1,e a method of evaluation, these questions are I] NOT APPLICABLE)
YES NO QUESTION Li LF Does the activity use a revised or different method of evaluation far performing safety arals.s .hanthat described in the CLB?
Fili Does the acuwir- use a revised or different method of evaluation for evaluating SSCs credited in safcer analyses than that described in the CLB?
If any ansa er is YES, a 10 CFR 50.59 Evaluxion is required If both answers are NO. describe the basis for the conclusion (attach additional discussion, as necessar.).
IH 3 TESTS OR E.NERL-ENTS If the nacti," ity is not a test or experiment, the questions in IIi.3.a and I113 b are 17 NOT APPLICABLE.
- a. A-nswer these twNo questions first YES NNO QUESTION Li Li Is the proposed test or experiment bounded by other tests or experinents that are described in the CLB?
Li Li Are the SSCs affected by the proposed test or experiment isolated from the facility?
If the answer to BOT[F questions in V.3.a is NO, continue to III.3.b. If the answer to EITHER question is YES, then describe the basis.
- b. AnswNer these additional questions ONLY for tests or ex-periments which do NOT meet the criteria given in ImI 3.a above If the answer to either question in IIL3.a is YES, then these three questions are li NCT APPLICABLE.
YES NNO QUESTION Li Li Does the activity utilize or ,ontrol an SSC-in a manner that is outside the reference bounds of the design bases as described in the CLB?
Li Li Does the activity utilize or control an SSC in a manner that is inconsistent with the anal-ses or descriptions in the CLB?
L] El Does the activity place the facility in a conditicn not previously e:aluated or that could affe:t the capability of an SSC to perform its intended functions?
the If any ans%%er in [I1.3.b is YES, a 10 CFR 50.59 Evaluation is r.equired If the answers ir III.3.b are ALL NO, descnbe basis for the conclusion (attach additional discussion as necessary).
PBF-1515c R.ercn:- N?51S Rc,.ision0 10,'2"4 01
Point Beach Nuclear Plant SCR ,0o1- O 9 10 CFR 50.59172.48 SCREENLNG (NEW RUL)Enf) sc .u.o-a*,page Page 4 Part IV - 0 CFR 50.59 SCREENING CONCLUSION (Resource Manual 5.. 1).
heck all that apply:
A 10 CFR 50 59 Evaluadon -,s El required or 0 SOT required.
A Point Beach FS.-AR change is E' required or 0 NOT required. Ifan FS.AR change is required. then initiate FanSA. Char-c Request (FCR) pe: N'P 5.2 6.
A Rcgulatorv Commitment (CLB Commitment Database) change is El required or ED NOT required. 1f1a Regulatory Commitment Change is required, initiate a comrrutment change per NP 5.1.7.
T A Technical Specification Bases change is El required or 0 NOT required. If a change to the echnical Specification Bases is required. then initiate a Technical Specification Bases change per NP 5.2.15.
Requirements A Technical Requirements Manual change is [I required or 0 NOT required. If a change t(, the Technica!
Manual is required. then initiate a Technical Requirements Manual change per N-P 5.2 15.
--- -----------.............. 10 CFR 72.48 SCREEN ........................................-----
-NG ---------
to determine the NOTE: NEI 96-07. Appendix B. Guidelirnes for 10 CFR 72.48 Implementation should be used for gruidance proper responses for 72.48 screenings.
PART V (72.48) - 10 CFR 72.48 LNITIAL SCREENING QUESTIONS Part V deterri,.z-'; if a full 10 CFR 72.48 screening is requL-ed to be completed (Parts VI and VII) for the proposed activity.
vES NO QUESTION
[* Does the proposed activity involve IN ANY MANNER the dry fuel storage cask(s), the cask transfer/transport equipment, any ISFSI facility SSC(s), or any ISFSI facility monitoring as follows- Multi-Assembly Sealed Basket (MSB). MSB Transfer Cask (NMTC), MTC Lifting Yoke, Ventilated Concrete Cask (VCC), Ventilated Storage Cask (VSC), VSC Transporter (VCST), ISFSI Storage Pad Facility, ISFSI Storage Pad Data/Communicaucn Links, or PPCSIISFSI Continuous Temperature Monitoring System?
El
[- ~ Does the proposed activity involve IN ANY MANN'ER SSC(s) installed in the plant specifically added to support cask loading/unloading activities, as follows: Cask Dewatering System (CDW), Cask Reflood System (CRF), or Hydrogen Monitoring System?
El
- Does the proposed activity involve I; ANY MiAN'NER SSC(s) needed for plant operation which are also used to support cask loading/unloading activities, as follov-s: Spent Fuel Pool (SFP), SFP CooILng and Filtration (SF),
Primary Auxiliary Building Ventilation System (VNPAB), Diumming ,Area Ventilation System (VN"DP,-\).
RE-105 (SFP Low Range Monitor), RE-135 (SFP High Rangt Monitor), RE-221 (Drumming Area Vent Bridge, Gas Monitor), RE-325 (Drumming Area Exhaust Low-Range Gas Monitor), PAB Crane, SFP Platform Truck Access Area, or Decon Area?
E]l* Does the proposed activity involve a change to Point Beach CLB design c-riteia for external events such as earthquakes, tornadoes, high vinds, flooding. etc.?
El E9 Does the activity in,,olve plant heavy load requirements or procedures for areas of the plant used to s'Jpport cask loadingr/uloading activities?
El , Does the activity involve any potential for fire or explosion where casks are loaded, unloaded, transported or stored?
to the questions in It ANY of the Part V questions are answered YES, then a full 10 CFR 72.48 screening is required anA ansNxers If ALL the questions in Part V are an=wered NO, then check Parts VI and V1I as not Part VI and Part VII are to be provided.
aiplhcable. Complete Part VIII to document the conclusion that no 10 CFR 72.4S evaluation is required.
PDF-tS15c ReZf-rert N? 5 1S Revision 0 10f"24/01
% ai&
Poin.t Ecach Nuclear ?lant SCR ODI"-07 c?
10 CFR 50.59172.43 SCREENING (NEW RULE) vc.::sCR nL.:.- cr. ,;l pages DESIG.V FU'YCTIO,V
"-ARTVI (72.-8) - DETERSIINE IF THE CHANGE INVOLVES A ISFSI LICENSING BASIS ALL the qLestions in Panr V are then Part VI is 9*NOT APPLICABLE)
O..0.
res-a-ons" Compare the proposed activity to the relet ant por:ions of the ISFSI licensing basis and ans-'.er the fcl!owig YES -NO QUESTION swutctures. s. stems and E L El Does the proposed aczi%iy in'ohNe cask/ISFSI Safety Analbses or pianticas-i&ISFSI components (SSCs) credited in the Safety Analbses?
%.naihses'"
[- El Does the proposed acti'it) intclhc plant. cask or ISFSI SSCs thatsuppon, SSC(s) creined ii' the Safet'.
for pre,,*ntion of a
" l Does the propo:ed activity in%olve plant, cask or ISFSI SSCs mhose function is relied upon could impact SSC(s) credited in the Safe,'. Ana!' ses' radioactive relase. OR %Nhosefailure perform functions that are
[E E] Does the proposed activity involve caskilSFSI described SSCs or procedurz! controls that to comply ;iqth. regulation., license ccndtons, CoC conr.duons. or orders?
required by, or othervise necessary basis'
[] El Does the activity inrolhe a meihodofevalantton described in the ISFS! lhcens-rqg El LI Is the activity a test r expertinent? (i e, a non-passive activity"- hich gathers data) product barrer(DBLFPB)?
[E Ej Does the activity exceed or potentially affect a cask desig'z basis hnitrfo afiss:on is ansu'cred YES, a 10 CFR 72.4S Evaluation is required)
(NOTE: If Tfl.S questions ind document the 10 CFFR 72 48 sareen.ing in the If the ansNsers to ALL of these questions are NO. mark Parts VII as not applicable.
conclusioi section (Part VIII) function(s). method of e' aluation(s) or DBLFPB(s)
If any of the aboN e questions are marked YES identify below the specific design ADVERSE EFFECTS (N'EI 96-07, PART 1I0 (72.4S) - DETERMINE WHETHER THE ACTIVITY IN'VOLVES Appendix B. Section B.4.2.1)
- I NOT APPLICABLE)
(If ALL. the questions bn Part V or Part VI are ansm ered NO, then Part VII is effect on a desip fun:5on. Any YE..S as;er mea-ns that a Ans%%er the folloiving questions to determine if the activity has an adverse 10 CFR 72.48 Evaltmtion is required; EXCEPT %,.herenoted in Part VII.3.
VII. I Changes to the Facility or Procedures YES LNO QUESTION ISFSI SSC credited in safety El El Does the activity adversely affect the designf.nction of a plamn. cask, or anal) ses?
of a p*ant, El El Does the activity ad. ersely affect the method of performing or controlling the desgnfictor, Scask, or ISFSI SSC credited in the safe,.," anah)ses?
Ifbothans%%crs ane NO. describe thebasis for -he cclsion If any ans:'er is YES, a 10 CF 72.43 Evaluation is required.
(attach additional discussion, as necessar,).
?.efe-.,.." N?C-II 9U Rc',ision D 1or~Z-GCI
.Pe i-cr0tO2
- *.. . .I'll . . ...
--
- T* * - * ....
Point Beach Nuclear Plant SCR o 0',9t[
10 CFR 50.59/72.48 SCREENING (,NEW RULE) Vrif: SC. rm=*>, on ai p-e; Pate 6
-" " Changes to a3lethod of Evaluation (If the activity does not involve a method of e',aluation. these questions are C3 NOT APPLICABLE)
YES NO QUESTION than that 0l El Does the actijity use a revised or different method of evaluation for performing safety analyses described in a cask SAR?
[3 El Does the activity use a revised or different method of evaluation for evaluating SSCs credited in saferN analyses than that descnr-ed in a cask SAR?
describe the basis for the conclusion If any answer is YES, a 10 CFR 72.48 Evaluauon is required. if both ans%%ers are NO.
(attach additiornal discussion, as necessar,)
10I1.3 Tests or Experiments NOT APPLICABLE.)
(if the activity is not a test or experiment, the questions in \V1.3 a and VHI.3.b are 0l
- a. Ansiier these rmo questions first:
YES INO QUESTION in the cask
[1 0l Is the proposed test or expernment bounded by other t.ests or experiments that are descnbed ISFSI licensing basis?
or ISFSI facility?
[I Cl Are the SSCs affected by the proposed test or experiment isolated from the cask(s) question is YES, then briefly describe If the ans,.er to both questions is &NO,continue to VII 3.b. If the ansvier to EITHER the basis.
not meet the criteria given in VII.3.a above.
- b. Answer these additional questions ON'LY for tests or ex-periments i-hich do are [E] NOT APPLICABLE:
If the ansv-er to either qaestion in VII.3 a is YES, then these three questions YES NO QUESTION of the design El El Does the activity utilize or control an SSC in a manner that is outside the reference bounds bases as desc-ibed in the ISFSI licensing bas:s?
incorsistent with El El Does the activity utilize or control a plant, cask or ISFSI facility SSC Ln a manner that is the analyses or descriptions in the ISFSI licensing basis?
evaluated or that ccdd affcct El Li Does the activity place the cask or ISFSI facility in a conditi)n not previously the capability of a plant, cask, or ISFSI SSC to perform its irzended functions?
If the aasiers awrall NO, describe the basis for the If any answNer in "VHI.3b is YES, a 10 CFR 72.48 Evaluation is required.
conclusion (attach additional discussion as necessary):
PBF.IlS1c Refx-enct %P5 18 Rcvision0 1t=4'01
Poin: Eca3ch Nuclear Plant 10 CER 50.59.172.43 SCRE1ENL--NG (NEW RULE)
?aLt, 7
-NRT VIII - DOCt2'IE.NT THE-CONCLUS-ION OF THE 10 CFR 72.4S SCREENING%
Cl1 e~k-311 tht pply:
A10 C-R? 72 45valuation is Flj recu~rzei or \OTrequired Obtainla scr-,cninrinux ber and pro, id-, the original to z:%rdsN12n., cment regardless oftecon:Iusion of tile 509 or 724 ce.n A VSC-24 cask Safety Analysizs Reocr, change is C] requirled or -15'NOTrequire-d Uf a VSC-24' cask- SAPI chan!4- ;s rcwuireýd. !henl contact the Point B.-3ch D.-% Fuel Storaee uouD su-;er-%isor.
A\Regu'iato~n Coinmitimunrt (CLB Coimnintment Database) change is (3 required -.). Z.NOT requir-ed if a PReemlaton Commliitiment Change is requircd. in~tiate a commnitmlent change er "P 5 1.7.
A char=e to thet VSC-2-1 10 CF-R 72.212 Site, Evaluation PRepor, is Elrequired or S?- -NOTrequired. If a VSC-2-1 it) CFR 72 212 Site E~aluation Report, change is required, then contact the Point Beach Dr; Fluel Stora~e group soper. isor.
P[3 F. iS. P5tS Rcet:ionO0 to 2.1 IFýZ-
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 2 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 37 12/14/2001 REACTOR TRIP OR SAFETY INJECTION Page 1 of 33 A. PURPOSE
- 1. This procedure provides directions to verify proper response of the automatic protection systems following manual or automatic actuation o'f a reactor trip or safety injection, assess plant conditions, and direct the operator to the appropriate recovery procedure.
- 2. This procedure is applicable for all plant conditions where RCS hot leg temperature is greater than or equal to 3500F with accumulators in service, and assumes the RHR system is not in service for decay heat removal and all SI system components are available.
B. SYMPTOMS OR ENTRY CONDITIONS
- 1. The following are symptoms that require a reactor trip. if one has not occurred:
REACTOR TRIP SIGNAL SETPOINT AT Overtemperature Variable AT Overpower Variable RCP Breaker Trip Low Voltage STPT 21.1 RCP Breaker Trip Low Frequency STPT 21.1 RCS Loop Low Flow 93 %
S/G Low-Low Level 25%
S/G Low Level with Flow Mismatch 30% of span PZR Pressure Low 1925 psig PZR Pressure High 2365 psig PZR Level High 80%
NIS Power High Range. High Level 107%
NIS Power Low Range. High Level 20%
NIS Intermediate Range Current equal t6 25%
NIS source range 5 X 105 counts/sec Manual Reactor Trip N/A Turbine Trip N/A Safety Injection N/A I__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
FOLDOUT PAGE FOR EOP-0 UNIT 2
"*RCS subcooling - LESS THAN [600F] 30*F
"*SI pumps - AT LEAST ONE RUNNING AND CAPABLE OF DELIVERING FLOW
"*Operator controlled cooldown : NOT IN PROGRESS
- 2. FAULTED S/G ISOLATION CRITERIA IF any S/G pressure trending lower in an uncontrolled manner OR any S/G completely depressurized. THEN the following may be performed:
- a. Isolate feed flow to faulted S/G.
- b. Maintain total feed flow greater than or equal to 200 gpm until narrow range level in at least one S/G is greater than [51%] 29%.
- 3. RUPTURED SIG ISOLATION CRITERIA IF any S/G level rises in an uncontrolled manner OR any S/G has abnormal radiation, AND narrow range level in affected S/G(s) is greater than [51%] 29%. THEN feed flow may be isolated to affected S/G(s).
- 4. AFW SUPPLY SWITCHOVER CRITERIA IF CST level lowers to less than 8 feet. THEN switch to alternate AFW suction supply per AOP-23 UNIT 2. ESTABLISHING ALTERNATE AFW SUCTION SUPPLY.
- 5. ADVERSE CONTAINMENT CONDITIONS IF any condition listed below occurs. THEN adverse containment setpoint values in brackets. []. shall be used:
"o Containment pressure - GREATER THAN 10 PSIG OR "o Containment radiation level - GREATER THAN OR EQUAL TO 105 R/HR OR "o Integrated dose to containment - GREATER THAN 106 R
- 6. AFW MINIMUM FLOW REQUIREMENTS IF any AFW pump mini-recirc valve fails shut. THEN maintain minimum flow or stop the affected AFW pump as necessary to control S/G levels.
o P-38A minimum flow - GREATER THAN 50 GPM
" P-38B minimum flow - GREATER THAN 50 GPM "o P-29 minimum flow - GREATER THAN 75 GPM I
A Nuclear Poster Business Unit TEMPORARY CHANGE REVIEW AND APPROVAL Note: Refer Io NP 1.2 3. Temporary ProcedureChanges.for -equirements Pa-ý I of *-1 I - INITLATION Doc Number EOP-0 Current Rev 37 Unit PB2 Tcmp ChangC Nov7"t/o*-oili4 Document Title REACTOR TRIP OR SAFETY LNJECTION Existing Effective Temporary Changes BriefDescription MODIFY FOP F3R MINLMUM AFW FLOW TO INCLUDE LOW LA HDR PRESSURE (Identif* specific changes on Form PBF-0026c, D,,curnert Revie. and Apprnoalt ontnuatton, and u:lu.'lde sutth the package)
Z Initiate PBF-0026h and include- .;iththe change.
Other documents required to be e!feztix e concurrently with the temporary change Changes pie-screened according Io NP 10.3.1? 0 NO El YES (If y-, Lit rekerene. a.n cr-tnA on PBF.o-:6cA,*,-:* -.ai0 .3I?
Screening completed according ,uNP 10.3.1?.Z L NA ( YES Safety EvaluttionReouired? '. , NO 0] YES (if .Yeta,oCT edofcrtdortn .... a-..a-,th12-&2.. be ýbuj- E, c a
Determine if the change constitutes a Change Of Intent to the procedure by ev'aluating the following qucauons (If any answers are YES, a revision mz3be processed or final reievs and approals vhall be obtained befre: irnptmentinSg)
Will the proposed change: YES NO
- 1. Require a change to, affect or invalidate a requirement, commitment, c;iluauoil or description in the Current Licensing Basis (as defined in NP 10 3 1)?
2 Cause an increase in magnitude, si,-nificance or impact such that it should be processed as a revision?
"Z.Delete or modify a prerequisite, initial condition, precaution, limitation or other steps that I could have safety Eignificance or affect the procedure's margin of safet%?
- 4. Delete QC hold points, Independent Verification or Concurrent Check steps without the related step(s) that require the performance also being deleted? D ED
- 5. Change Tech Spec or ether regulatory acceptance criteria other than for rc-baseliing F. [
1 I purposes?
- 6. Require a chagee to the procedure Purpose or change the pro Sdr 6sssrlcuon. C3 0 Initiated By (pnnt~sigii) tA- ______________I__ Dite "
It - INITIAL APPROVAL This change is correct and complete, can be performed as written, and does not peusely affe.-Ipcrsormc! or nuclear safety, or Plant operating ccnditions. 7 Group Supcriisor(prnL'sCn) 7" A.0.AC, .- ',o,...c. ,.- I/i D.tc (Cannot be the II ' -
"Thisr.haiige does not adversely affect Pl*t. operating conditions (Sarct. Rei,)cd cledurcS ont,)
Senior Reactor Operator (print sign) 4 a r / 770 DatelIi .c. c]
(Cannot be th Iittor or rroup iupirmisor)
III - PROCEDURE OWNER REVIEW Q9 0 Pzrtnanent C] One-time Use E] Expiration Date, Event or Condition:
De old change until procedure completed (final review and approval still requited ma:tin 14 dlas of Initial appro; cI) 2 Qr/mSS Review NO ri Rquired (,Xdmi.*'NSR onl) [9 QR Rceicw Required [] MSS ReicwRew.quired iT-c. '*,PI (,si Procedure Owner (print/sign) edpg /v/*1te1I , Date ,
"T~ri*Chance and ,strnr-,~,ne eurcm~ents¢oer5etlv cr'-let~d rotc anrd e4 *ij IV - FINAL REVIEW AND APPROVAL.
,-"M'u't be cumrlletd ,Aitidn 14 days ofinitial appr-,)at) (The Initiator, QIt .rd Appro~al Authunti shall be indtpý ntihnt from erach other)
QRJ',LISS (prin:.'sign5 1A'-ii )'.t.. :rs ________ ae-Ž/ .
- --*" IndicaUs 'O 59 72 .13 apl'hcawtlhtw assesscd,.n" nec.s.arv syrceningsaluitions pcrtl.ncd d rn.imatien rn tdc as tw,v.h, thr a2.idwi.jI cros-disciphrnazy revic% required, and tfrequircd, performed hISS Mecting No Appro%al Authority (print sign) b. S'IA*3- Date /____-__
V - REVISION INFORMATION FOR PEIL-' ANEN'T CIIANGES /
Post Typing Re, g / 7w Q*A D./'c indwcale tIctpirr iiange(w) t ,',r se'a.cal) as apinowd and no otlher .imnge* 1,Oc toCE '-CL.CWnt Incorpora-ed into Re\ ision Number _, __ El'cc3iz c Dzi.':.t -,:..
REC'D JAN 1 1 2002 t; t
'-'S 0
F1.1 -0 26c RMe-.-..'C Mi" I .3 Revision 12 11.08.99 1 I,..
I .'
V ="PMwkw 1 111111111:111! -
r1r,:1111 NIL10ý
t, 4' Point Beach Nuclear Plant '- "
CONTINUATION DOCUMENT REVIEW AND APPROVAL Page .. Ž.. of Revision 37 Unit 2 Doc Number EOP-0 Title REACTOR TRIP OR SAFETY INJECTION Temporary Change Number
- Ol9 Description or Changes:
Step
- ChangefReason Co0 A 1-9, IA HEADER LOW PRESSUR.,E CHANGE: ADDED REFERE1NCE TO ANNUNCIATOR FOR THE AFW MINIUMF LOW REQUIREMENTS.
FOLDOUT REASON: TO ENSURE MINMIMUM FLOW IS MA*INTAINED THROUGH THE AFW P!5MS PAGE DURVAqG OPERATION.
Other Coennirnts
,hennot beneficial to tc-.icCrs for ulupl OCCurren ce identical informnaton or
' Note: Recording cf Step Nmba(s is not required Rcfcrc'ccs NP I I NP I 2 sr PBFRi026c Revi-sion 6 044L*01
11 Mimi I N Eli Mý m :4IM -
Point Beach Nuclear Plant TEMPORARY CHANGE AFFECTED MANUAL LOCATION Page of Procedure Number EOP-0 Revision 37 Unit PB2 Title REACTOR TRIP OR SAFETY LNIECTION Temporary Change Number F"*A)J .,qe / - ep9 Iq I - IMMEDIATELY AFTER INITIAL APPROVAL ON PBF-0026e (Non*Inc-nt changes)
(after Final Apprna&if change of intent involved)
Date This procedure change has been processed as follows: (Manual/Location) Performed El Copy included in work package for field implementation. (WO No.
I] Copy filed in Control Room temp change binder (Operations only). zZ-/2
-o
[ Original change package provided to 1',,O to obtain Procedure ONner Review (eg. Owne reiew my be coordinated by In-Group OA II, Procedure Writer. Procedure Supervisor. etc.) 1? -2 t, -o El El__ __
El__ __
El__ __
] .. 7.
Performed By (print and sign) C i, ae/2Ž~~
11- PROCEDURE OWNER REVIEW ON PI3F-0026e (inny be performed by OA 11,Procedur Writ(=, emC)
This procedure change has been processed as follows: (Manua!/Location)
- ] Copy sent to Document Control Distribution Lead for Master File.
(Not rmquired for one-time ue change)
[] Copy filed in Group satellite file. (Not required for one-Came use c.anges)
Copy fiicd in Group one-time use file.
[ Original Tcmp Change provided to 5 to obtain Final Approvals (e P. final approval mai b e coordnnzz-J by In-Croup OA I. Pr=cedure Wnicr. Prr,:rdure Superisor. etcC)
[]->
El c .,,. i/"
I..
Performed By (print and sign) (_ - ,.' £//-, t Date (2-'e i I
PBF-00261i R"* .... t3 o1* Refeeanct. NP 1 2 3
POINT BEACH NUCLEAR PLANT EOP-0 UNIT 2 EMERGENCY OPERATING PROCEDURE SAFETY RELATED Revision 38 1/10/2002 REACTOR TRIP OR SAFETY INJECTION Page 1 of 33 A. PURPOSE
- 1. This procedure provides directions to verify proper response of the automatic protection systems following manual or automatic actuation of a reactor trip or safety injection, assess plant conditions, and direct the operator to the appropriate recovery procedure.
- 2. This procedure is applicable for all plant conditions where RCS hot leg or equal to 3501F with accumulators in temperature is greater than heat service, and assumes the RHR system is not in service for decay removal and all SI system components are available.
B. SYMPTOMS OR ENTRY CONDITIONS
- 1. The following are symptoms that require a reactor trip, if one has not occurred:
REACTOR TRIP SIGNAL SETPOINT AT Overtemperature Variable AT Overpower Variable RCP Brealker Trip Low Voltage STPT 21.1 RCP Breaker Trip Low Frequency STPT 21.1 RCS Loop Low Flow 93 %
S/G Low-Low Level 25%
SIG Low Level with Flow Mismatch 30% of span PZR Pressure Low 1925 psig PZR Pressure High 2365 psig PZR Level High 80%
NIS Power High Range. High Level 107%
NIS Power Low Range. High Level 20%
NIS Intermediate Range Current equal to 25%
NIS source range 5 X 105 counts/sec Manual Reactor Trip N/A Turbine Trip N/A Safety Injection N/A I _ _ _ _ _ _ _ _ _ _ _ _ I _ _ _ _ _ _ _ _ _ _ _ _ _
FOLDOUT PAGE FOR EOP-0 UNIT 2
"*RCS subcooling - LESS THAN [60'F] 30'F
"*SI pumps.- AT LEAST ONE RUNNING AND CAPABLE OF DELIVERING FLOW
"*Operator controlled cooldown - NOT IN PROGRESS
- 2. FAULTED SIG ISOLATION CRITERIA IF any S/G pressure trending lower in an uncontrolled manner OR any S/G completely depressurized. THEN the following may be performed:
- a. Isolate feed flow to faulted SIG.
- b. Maintain total feed flow greater than or equal to 200 gpm until narrow range level in at least one S/G is greater than [51%] 29%.
- 3. RUPTURED S/G ISOLATION CRITERIA IF any S/G level rises in an uncontrolled manner OR any SIG has abnormal radiation. AND narrow range level in affected SIG(s) is greater than [51%] 29%. THEN feed flow may be isolated to affected SIGCs).
- 4. AFW SUPPLY SWITCHOVER CRITERIA IF CST level lowers to less than 8 feet. THEN switch to alternate AFW suction supply per AOP-23 UNIT 2. ESTABLISHING ALTERNATE AFW SUCTION SUPPLY.
- 5. ADVERSE CONTAINMENT CONDITIONS IF any condition listed below occurs. THEN adverse containment setpoint values in brackets. []. shall be used:
o Containment pressure - GREATER THAN 10 PSIG OR o Containment radiation level - GREATER THAN OR EQUAL TO 105 R/HR OR o Integrated dose to containment - GREATER THAN 106 R
- 6. AFW MINIMUM FLOW REQUIREMENTS IF any AFW AIR pump HEADER mini-recirc valve shut OR THENannunciator monitor andCOlmaintain A 1-9.
INSTRUMENT PRESSURE LOW fails in alarm.
minimum AFW flow or stop the affected AFW pump as necessary to control SIG levels.
o P-38A minimum flow - GREATER THAN 50 GPM o P-38B minimum flow - GREATER THAN 50 GPM o P-29 minimum flow - GREATER THAN 75 GPM
Nuclear Power Business Unit 4i TEMPORARY CHANGE REVIEW AND APPROVAL Mole: Refer to NP 1.23. Temporary ProcedureChanges,for requirements. Page I of I - INITIATION I Doc Number Document Title REACTOR TRIP RESPONSE Existing Effective Temporary Changes EOP-0.I Brief Description ADDED FOP ITEM TO ADDRESS AFW MINIMUM FLOW Current Rev 24 Unit PB1 Temp Change No (Identify specific changes on Form PBF-0026c. Document Review and Approval Continuation, and include Aith the package)
Z Initiate PBF-0026h and include with the change.
Other documents required to be effective concarrently with the temporary change: NONE Changes pre-screened according to NP 10.3.1? 0 NO [I YES (ifYes. isstrefenes aadensa onhPBF.0026:Xreferto.Np 10 31)
Screcning completed according to NP 10.3.1? Nl 0D YES NA Safewt Evaluation Required? E NO Dl YES (IfY t assm maybe proessedor rkai .r.....d&'poval shall btavwedbcfarete1rem.ting)
Determine if the change constitutes a Change Of Intent to the procedure by evaluating the following questions.
(If any answers arm YES, a revision may be processed or linal reviews and approvals shall be obtained before implementing)
Will the proposed change: YES NO I. Require a change to, affect or invalidate a requirement, commitment, evaluation or 0]
description in the Current Licensing Basis (as defined in NP 10.3. 1)?
- 2. Cause an increase in magnitude, significance or impact such that it should be processed as a 0]
revision?
- 3. Delete or modify a prerequisite, initial condition, precaution, limitation or other steps that El 0]
could have safety significance or affect the procedure's margin of safety?
- 4. Delete QC hold points, Indepcndent Verification or Concurrent Check steps without the El 0]
related step(s) that require the performance also being deleted?
- 5. Change Tech Spec or other regulatory acceptance criteria other than for re-baselining El 0]
purposes?
- 6. Require a change to the procedure Purpose or change the procedure classification? El 0 Initiated By (print/sign) J e"N t V_? M -,/y
ý_ _, I Date __________
1- INITIAL APPROVAL e This change is correct and complete, can be performed as written, and does not a 'ersely affect pe, onnel or nuclear.safety, or Plant operating conditions. : / /
Group Supervisor (print/sign)12"1-1" -. .1 5' 4C - I/A .
/ý I s-/ *ate _ /. ca
_ _ . .,..,~anno
.... , s_ am_,uas-or-j ,* * / .* -
- kt~annot De Me Initiator) lo" This change does not adversely affect Plant operating conditions. (SaeC, Rclated procedures only)
Senior Reactor Operator (print/sigp) LCV.* V erC ' sA. I/ <Z "' _ Date (Cannot be the Initiator or Group hpiLaor)
Irl - PROCEDURE OWNER REVIEW Pcrmanent El One-time Use El Expiration Date, Event or Condition:
El Hold change until procedure completed (final review and approval still required %N 14 days of initial apploval)
El QRIMSS Review NOT Required (Adm .jNSyRly) [] QR Reviewe wRequired (RP.ý,.manis Procedure Owner (print/sign) Date This Chanve and supportin rei*urements
' corr-ecly completed and orocessed IV - FINAL REVIEW AND .APPROVAL S(Must be completed within 14 das of initiAl approval) (T Initiator, QR and Appro1al thL.-'it. shall be Independent from each other)
CP ASS (prin~sin / -,,.-d! ni... Date/t/11a 1,tona Indicates 50 59/72 48 appl.zzbility assessed, any necessary screenings cval-ationperforfm.edd-:errnin..omde.asto%%he',heradditton3I cross-disciplinary review required, and if required. performed. 1/
Approval MSS Mct~ing Authority,'p.nt/sign)
No. " '/z-/". ---. 6* A Date Dt ---- ',
V - REVISION INFORMATJIN FOR PERIMANEN'fCHA%'.::5 Post Typing Review (print/sign) /"-' -.-
Indicates temporary change(sI incorporated exactly as appro%ed -nd naooth=r-hani mi7do.,oi..ent 7 "
Incorporatcd into Revision Number 2. 5 Eff,:ctive Date DEC 1 4 201 1401C1OFILMED Rsn 21 REC'D D0E9C 17 References NP 1.2 Re%ision 12 11/08199 FEtB 0 1 zUoZ
DEC 1 4 2oa1 Point Beach Nuclear Plant DOCrUMENT REVIEW AND APPROVAL CONTINUATION Page ý of -.
Doc Number EOP-0.1 Revision 24 Unit I Title REACTOR TRIP RESPONSE Temporary Change Number goO i - C2- ""
Description of Changes:
Step Change/Reason CHANGE: Added AFW minimum flow requirements for the AFW pumps.
REASON: To prevent damage to the AMF'V pumps on a i, ss of instrument air due to the AXW Fpump mini-recirc valve failing shut w;h minimum flow throughi the pump is less than required to cool the FOP pump 4-1-
+
.4 4-I i
I Other Comments
- Nutc Recording of Stp Numberts, is not ::qutr:d for multiple occirremces of id.:nticat information or uhen not beneficial to r-:e'NerS.
r13r-00,:6c
Point Beach Nuclear Plant TEIMPORARY CHANGE AFFECTED MANUAL LOCATION Pa-e
- of Procedure Numbcr EOP-0.1 Revision 24 Unit PB1 Tide REACTOR TRIP RESPONSE Temporary Change Number 2ao / -0 g-2 I - IMMEDiATELY AFTER INITIAL APPROVAL ON PBF-0026e (Non-Intent changes)
(?.lcr Final Approval ifcharnge of intent in%ohed)
Date This procedure change has been processed as follo~is: (Manual/Location) IPerformed El Copy included in work package for field implementation. (WVO No. )
F] Copy filed in Control Room tcmp change binder (Operations only).
Criginal change package provided to C C,Qr, to obtain Procedure Ovner RcviCw (e g,.o,,nr revciex may be coordinated by In-Ga-oup OA II. Prccedure U ntcr, Proc-dure Supemisor, cc.) I
[ El Performed By (print and sign) e-A- C\
11 - PROCEDURE OWNER RE-VIEW` ON PBF-0026e I~&
(=vy be performed by OA If, Procedure Writer, etc)
L ,')~+/- Date 1ý)
I Date This procedure change has been processed as follows: (Manual/Location) Performed Copy sent to Document Control Distribution Lead for Master File. / 3 I
[
(No, required for one-time use change)
El Copy filed in Group satellite file. (Not required for one.time use changes)
El Copy filed in Group one-time use file. _
[ Original Temp Change provided to I to obtain Final Approvals I %II te g final appre- ai may be coordina:ed ,>% In-Group OA IL. Procedure Writer, Procedu.re Superscr. c tr:.) !
.'-1* I 12-.3 cf c*
gJ] .('$.1\o('* ____ _
I" C-F %k(r,-,*\,c (r .. 4..
Ia Perfomied 13y (peint and sign) , lA'-e~C, / .* .... Date Purl-c.)2(h Rc% mol 5 C{ illg'
Point Beach Nuclear Plant SCR _-- 0 (-O 5.Sg tv-.. CR:-s.-,br
- era-.-.s
, 10 CFR 50.59i72.48 SCREEN.NG (NEW RULE)
¶ Page I
)f Proposed Activity: Unit I EOP Re'.. '5. Unit 2 EOP-F - Rev. -6. Unit i EOP-0 I. Rev-2. Urit 2 EOP?0 1 - Re% 23 Associatcd Reference(s) CR 01-2278 Ac-or 2 Bob Wartenberg ,./ Date.-
Prepared b.:
Name (Print) ,na V ua.ure Reviec' ed b% Clayton Graves__________
Name (Print) ' / Sjiature THE PLANT A.-ND ISFSI LICENSING PART 1 (50.59/72.48) - DESCRIBE THE PROPOSED ACTIVITY AND SEARCH BASIS (Resource Manual 5.3.1)
Aplendih B. Guidelines for NOTE: The "NMIC 10 CFR 50.59 Resource Manual" (Resource Manual) and NNE, 96-07.
10 CFR 72.48 Implementation should be used for guidance to determine the proper respanses for 10 CFR 50.59 and 10 CFR 72.43 screenings.
s:reening. (The 10 CFR 40 59 172.43 1.1 Describe the proposed activity and the scope of the actiity being co ered by this and pre-screening process review of other portions of the proposed a-tvity may be documented via the'appi:abiitrv requirements in N'P 5.1.3.) Appropriate descriptiv'* material may be attached.
fo!dout page item. "AFW Mirimuni A foldout-page item is being added to Units 1 & 2 procedures EOP-0 and EOP-0 ! .The pumps in the case of a failed closed rr;,-ii-recirc Flow Requirements", shall address minimum flow required by the AFW valve on any running AFW pumps.
Report (FSAR), FSAR Cha-nge Requests 1.2 Search the PBNP Current Licensing Basis (CLB) as follo%%s" Final Safety Anal, sis CLB (Regulatory) Corm,-itment Database.
(FCRs) wvith assigned numbers, the Fire Protection EvaLation Report (EPER). the Bases, and the Technic:l the Technical Specifications (both Custom and Improved), the Technical Specifications VSC-24 Sa-ert Ana-lysis Report, the V ~C-24 Certificate Requirements Manual. Search the ISFSI licensing basis as folioN s:
and the VSC-2-' 10 CFR 72.212 Site Evaluation Report.
of Compliance, the CLB (Regulatory) Commitment Database, requirements, and me,.hods of evaluation for both the plant and for the "Describethe pertinent design function(s), performance in the above documents (by document caskfISFSI as appropriate. Identify where the pertinent information is described 2) section number and title). (Resource Manual 5.3.1 and NEI 96-07. App. B, B FSAR 10.2, Au'iliary FeedNater System S.e:ification (ITS)? Changes to 1.3 Does the proposed activity involve a change to any Custom or Improxed Tecb~_c*
N,.,*'iau Section 5 3. 1.2)
Technical Specifications require a Licernse A*nendment Request (Resource Technical Specifcation Change" D Yes Z :No be and Nxhy it is required.
If a Technical Spýcification change is required. explain vxhat the change should a chzngcztoo a&,-,. con-Jitons te.rms, caskt or spectira:*er.n -ncorpor-ated rcqutre a COC C-,1- in any V5SC-24ittcask ar.nendn.e rcqucsL 14 Does the proposed Certificate of Compliance involve Chances activir."(CoC)? VSC-24 Certificate of Ccr-....
[] Yes 0 No explain v hat L:.ie ch'.nce should be and x.hy it is required If a storage cask Certificate of Compliance change is required.
NP : , I s
', B F -r s1i:'<..c
Point BeachNucle," Plan, SCR tZ)l- 0 7 "F 10 CFR 50.59172.48 SCREENING (.NEW RULE) ,'- SC*R .,ur.,.. on al, p-:
10 CFR 50.59 SCREENING ------------------------------------------------
PA-RT I] t,50.59) - DETERMI NE IUTHE CHANGE INVOLVES A DESIGNFLYCTIO.N (Resource Manual 5 3.2)
Comp,ure ,,the proposed act;-ity to the relevant CLB descriptions, ar'd ansNer the following questions:
YES INO QUESTION
[-] Does the proposed activity i;n'ol, e Safery Analyses or structures. s,.stems and components (SSCs) ciedited in the Safer" Analyses'
[ Does the proposea activit. invol e SSCs that support S3C's) credited in the Safezy Analyses?
[]- 2 Does the proposed actiity invol, e SSCs ihose failure could iniidate a -ransient(e.g. reactor urip. loss of feedarer.
etc ) or accident, O_.R ,hose failure could impact SSC(s) credited in the 'e.y Anal;sos?
E] Z Does the proposed activity in, olve CLB-descnbed SSCs or procedura! . -cols that perform functions that are ruquired by, or othenrise necessary to comply with, regdations. license condions, orders or techrucal specifications?
O3 0 Does the activity involve a method ofevc!aation described in the FSAR,
[] 0] Is the acti~ity a test or exper:nment? (i.e, a non-passive activity wNhich gathers data) 03 0Z Does the activity exceed or potentially affect a design basis limitfo 'afissionproduct barrier(DBLFPB)?
(NOTE: If THIS questions is ansNered YES, a 10 CFR 50.59 Evaluation is required.)
"- Ie ansers to ALL of these questions are NO. mark Part III as not applicable, document the 10 CFR 50.59 screernng in the
.lusion section (Part IV), then proceed directly to Part V - 10 C "R 72.43 Pre-screening Questions if any of the above questions are marked YES, identify below the specific design function(s), method of e aluation(s) or DBLFPB(s) involved.
FSAR 10.2 states each AFW pump has an AOV controlled recirc line back to the CST to ensure minimum flo;, to dis-sipate heat. Th.s change ensures the minimum AFW flow requiements wrill be maintained on any running AFW punp il the case of a failed shut AFV/
miini-recirc flow control valhe.
PART III (50.59)- DETERNMINE NWHETHER THE ACTMTY LNVCLVES ADVERSE EFFECTS (Resource Manual 5 3.3)
If ALL tht questions ;.n Part U are answered NO, then Part III is [0 NOT APPLICABLE.
Ans,,er the following questions to determine if the activity has an cdverse effe:ton a desig fuunction Any YES arnser means that a 10 CFR 50 59 Evaluation is required; EXCEPT %%herenoted in Part 111.3.
1I. 1 CI-LA.NGES TO THE FACILITY OR PROCEDURES YES NO QUESTION Z Does the activity ad'.ersely affect the des:gnfrictionS[i of an SSC credited in safe*y anal-, sos" 9 0 i Does the acti-,ity adversely affect the -.ethcd of perforrrning er corzcilLrig the design fincr:on of an SSC credtted in the S.feru]Nl; ses?
If any answer is YES. a 10 CFR 50.39 Evaluation is req -red. ILfboth answers m:y .__, descnbe the txasis for the conclusiccn
"(attach-ddiuonal discussion as nec'ssan)
Ths chanoe ensures that minrmum recirc flow requirements as itated in FSAR 10.2 are not violated I
SPBF-15I.4c :- :. "".!
Point Beach Nuclear Plant SCR o-o~ i5' 10 CFR 50.59172.48 SCREENING (NEW RULE) V'fv, sc. .m-. on all pg-s Page 3 CILAN'GES TO A .METHOD OF EVALUATION (If the activity does not involve a method of evaluation, these questions arc E] NOT APPLICABLE.)
YES NO QUESTION El [] Does the activity use a revised o" different method of evaluation for performing sa-ety anil ses than Ohat described in the CLB?
E] El Does the activity use a revised or different method of e,aluation for e' aluating SSCs credited in safety analyses than that described in the CLB?
If any ans,%er is YES, a 10 CFR 50.59 Evaluation is required. If both ansi'ers are NO. describe the basis for the conclusion (atnacn additional discussion, as necessary.).
111.3 TESTS OR E.\TEREMEN-T7S If the activity is not a test or experiment, the que;tions in III.3.a and IH.3.b are [] NOT APPLICABLE.
- a. Ans%%er these two questions first:
YES NO QUESTION El El
[] Is the proposed test or experiment bounded by other tests or experirnents that are described in the CLB?
El El Are the SSCs affected by the proposed test or experiment isolated from the facility?
If the answer to BOTH questions in V.3.a is NO continue to III.3.b. If the answer to EITHER question is YES, then describe the basis.
- b. Answer these additional questions ONLY for tests or experiments which do NOT meet the .'rteria given in [II.3.a aboe.
If the answer to either question in 1113.a is YES, then these three questions are [] NOT APPLICABLE.
YES NO QUESTION
[E El Does the activity utilize or control an SSC in a manner that is outside the reference bounds of the design bases as described in the CLB?
El E- Does the activity utilize or control an SSC in a manner that is inconsistent with the analyses or descriptions in the CLB?
El El Does the activity place the facility in a condition not prev-iously ev-auated or that could affect the capability of an SSC to perform its intended functions?
the If any ans%%er in III.3.b is YES, a 10 CFR 50.59 Evaluation is required. If the answers in IfI.3.b are ALL NO, describe basis for the conclusion (attach additional disc'ussior. as necessary):
PBF-1515c a.%eeNP 51 S
Point Beach Nuclear Plant SCR ?00 1- ) 9f 2 10 CFR 50.59/72.43 SCREENLING (NEW RULE) Vc,,. SC?.R*-.-,- ai! ;ag.
Page
"*- IN - 10 CFR 50.59 SCREENLNG CONCLUSION (Resource Manual 5.3 4)
CIeck al that ::; ply:
A 10 CFR 50 5yI Evaluation is [] required or Z NOT required.
A Point Beach FSAR change is [] required or E1 NOT required lf an FSAR change is rzquired, then iniutate an FS.-.R Change Request (FCR) per NP 5.2 6.
A Regulntorv Commitment (CLB Commitment Database) change is El required or ', NOT requircd If a Regulaton Commitment Cbhage is required, initiate a cormmutment change per NP 5.1.7.
A Technical Specification Bases change is [l required or Z] NOT required. if a chan._e zo the Technical Specification Bases is required, then initiate a Technical Specification Bases change per NP 5 2.15 A Technical Requirements Manual change is C) required or 2' INOT required Ifa cha-:ge to the Techrnical Requirements Manual is required. then initiate a Technical Requirements Manual change per NP 5 2 15
10 CFR 72.48 SCREEIN G --------...------------------------------------------------
the NOTE: NEI 96-07. Appendix B. Guidelines for 10 CFR 72.48 implementation should be used for guidance to determine proper responses for 72.43 screeiings.
PART V (72.4S) - 10 CFR 72.48 LNITL.L SCREENING QUESTIONS Pan V determines if a full 10 CFR 72.48 screening is required to be completed (Parts \-i and %-II) for the proposed activ'.tV S INO QUESTION transport 0' 1& Does the proposed activitc involve IN ANY MANNER the cry fuel storage cask(s), the cask transfer, Basket equipment, any ISFSI facility SSC(s), or any ISFSI facility monitoring as follow s: Mulu-Assembly Sealed (MSB), MSB Transfer Cask (MrTC), MTC Lifting Ycke, Ventilt.ed Concre:e Cask (VCC). Ventilated Storage Cask (VSC), VSC Transporter (VCST), iSFSI Storage Pad Facility, ISFS! Storage Pad DatalCormaunication Links or PPCS/ISFSI Continuous Temperature Monitoring System?
El [ Does the proposed activity in%,olve IN ANY MANNER SSC(s) installed inthe plant specifically added to support cask loading/fuloading activities, as folloi's: Cask Devatering System (CDW), Cask Reflood System (CRF), or Hydrogen Monitoring System?
El [ Does the proposed activity involve IN ANY MANNER SSC(s) needed for piant operation N%!fich are also used to support cask loading/unloading activities, as follows: Spent Fuel Pool (SF'P), SFP Cooling and Filtration (SF),
Primary Atuxiliary Building Ventilation System (VNPAB), Drunmming Area Ventilation System (VT)R.),
RE-105 (SFEP Low Range Monitor), RE-135 (SFP High Range Monitor). RE-221 (Drummirg Area VentBrdge, Gas Monitor), RE-325 (Drumming Area Exhaust Low-Range Gas Monitr), PAB Crane, SF? Platform Truck Access Area, or Decon Area?
El [* Does the proposed activity involve a change to Point Beach CLB desip cr-tena for e-ternal events such as earthqualkes, tornadoes, hie winds, flooding, etc.?
El E*. Does the activity involve plant heavy load requirements or procedures fcr areas of the plant used tc support cask loading/unloading activities'"
or storec El I. Does the activity involve any potential for fire or explosion %%here :caks are leaded. un:loaded. =-.--,_crted
- .nd a:,si'ers :o th-e questions in If ANY of the Part V questions are answered YES, then a full 10 CFR 72.43 screeniL.g's required check P,-ars \V and \11 as not rt VI and Part VII are to be provided If ALL the questions in Part V are ansvered NO, -tren that no I0 CIFR 72 4S e,.'audtion :s requwred
,,plicable. Complete Part VIII to document the conclusion
.1 PBF- 513%: "* \..15
Point Beach Nuclear Plant SCR 74) Dj -
_. _7 _ _ "
10 CFR 50.59/72.4S SCREENING (NEW RULE) V'* s C c. onS;, pgs Pase 5 VI (72.48) - DETERMINE 'T IF THE CHANGE INVOLVES A ISFSI LICENSCNG BASIS DESIGN FUNVCTiON
(. ,LL the questions in Part V are NO, then Part VI is i9NOT APPLICABLE.)
Compare the proposed activity to the re!cant portions of the ISFSI licensing basis and ans'e: ',the folloring questions:
YES NO QU;ESTION E] Does the proposed activity involve casklSFS[ Safety Analyses or p!ant'caskriSFSI structures. systems and components (SSCs) credited in the Safety Analyses?
El El Does the proposed activity inolve plant, cask or ISFSI SSCs that supprt SSC(s) credited in the Safety Anal ses?
El Does the proposed activity in,.olve plant. cask or iSFSI SSCs vhose function is relied upon for pre ention of a radioactive release, OR %Nhosefailure could impact SSC(s) credited in the Sal'ery Anayses?
[ [j Does the proposed activity inolve caskfISFSl described SSCs or procedural controls that perform functions that are required by, or othenvise necessar; to comply with, regulations, license condiuons. CoC conditions, or orders?
9 El El .Does the activity involve a method of evaluation described in the ISFSI licensing basis
[] El Is the activity a test or expernment? (i e, a non-passive activity which gathers data)
El El Does the activity exceed or potentially affect a cask design basislimitfor afissionproduct barrier(DBLFPB)?
(NOTE: If THIS questions is ans%%ered YES, a 10 CFR 72.43 Evaluation is required.)
screening in the If the answers to ALL of these questions are NO. mark Parts VII as not applicable, and document the 10 CFR 72.48 conclusion section (Part VIII).
DBLFPB(s)
-'y of the above questions are marked YES, identif below the specific design function(s). method of e.aluation(s) or ved.
96-07, PART VII (72.48) - DETERtMLNE WHETHIER THE ACTMTY INVOLVES ADVERSE EFFECTS (NEI Appendix B, Section B.4.2. 1)
(if ALL the questions in Part V or Part 'I are answ&ered NO. then Part VII is [ NOT APPLICABLE.)
means that a "Answerthe following questions to determine if the activity has an adverse.effect on a design function. Any YES ans_%er 10 CFR 72.48 Evaluation is required; EXCEPT ,here noted iri Part VIL.3.
VII. I Changes to the Facility or Procedures YES NO QUESTION El El Does the activity adversely affect the designfiunction of a plant, cask. or ISFSI SSC credited in safety analyses?
ofa plant, El El Does the activity adcrely affect the method of performring or contrclling the designfunction 9
cask, or ISFSI SSC credited Ln the safety analyses descnbe the basis far the conclusion Ifany ansver is YES, a 10 CFR 72.43 Evaluation is required. Ifboth ansivers are NO.
(attach additional discussion, as necessa,"s)
PBF-iSlS, R..-.nc N? 5.-1 R.,islon(0 10,"24:01
Point Eeach Nuclear Plant SCR ______'-___9 10 CFR 50.59172.4S SCREEN-NG (,.NEW RULE) vOr s Pace 6
' 2 Changesio a Method of E'aluation (If the :cu', ir" does not in: olve a method of e* aluation. these questions are ..NOT APPLICABLE.)
YES NO QUESTION 0l [] Does the activity use a revised or different method of evaluation for performing safety analyses than that described :n a cask SAR?
F7
[2 Dces the activity use a re' ised or different method of evaluation fbr e- aluating SSCs credited in safety ana!)ses than that described in a cask SAR?
If any anscr is YES. a 10 CFR 72.48 Evaluation is required If both answers are No, describe the basis for the ccnclusion (attch addationl discussion, as necessar,)
Vi1 3 Tests or Experiments (If the activir, is not a test or experiment, the questions in VI.3.a and VII.3.b are El NOT APPLICABLE.)
- a. Ans-,%er these two questions first:
YES NO QUESTION ',
El [] Is the proposed test or experiment bounded by other tests or experiments that are described in the cask ISFSI licensing basis?,
Dl Dl Are the SSCs affected by the proposed test or experiment isolated from the cask(s) or ISFSI facility?
If the answser to both questions is NO, continue to VII.3.b. If the answer to EITHER question is YES, then briefly describe the basis
- b. .NsANer these additional questions ONLY for tests or experimnents which do not meet the criteria given in. VII.3 a abo,,e.
If the ansiwer to either question in Vfl.3 a is YE.S. then these three questions are E] NOT APPLICABLE:
YES NO QUESTION
[I El Does the activit" utilize or control an SSC in a manner that is outside the reference bounds of the design bases as described in the ISFSI licensing basis?
El [E Does the activity utilize or control a plant, cask or ISFSI facility SSC in a manner that is incon'stznt with the analN ses or descriptions in the ISFSI licensing basis?
El El Does the activity place the cask or ISFSI facility in a condition nct previously evaluated or tU=t could affect the capability of a plant, cask, or ISFSI SSC to perform its intended functions?
If any ansxier in VII.3 b is YES. a 10 CFR 72 4S Evaluation is required. If the an-smers xre all N__O_, describe the basis for the conclusion (attach additional dis:ussion :s necessar.):
PB"-I 5 1.c I., ¢so 0 1 '*.' 01 -t.--'.:T NF:! 1 S
Point Beach Nuclear Plant SCRC". *;O&!-
10 CFR 50.59172.48 SCR.EEN'ING (.-NEW RULE) Vc:.,:- SCR-:;
'T "V,' - DOCUMENT THE CONCLUSION OF THE 10 CFR 72.43 SCREENING Chte:.k all :i.at appl,y A 0 CF.., 72.!S Evaluation is E] required cr Q,5NOT required. Obtain a .. r.enm. w"rid pr.vide. hte to RecordS Ma13Cnagement regardl.ss.f the conclusicn of tht 50.59 or 72.48 screemnms is A VSC-24_ c.sk Safety Analysis Report change is [3 required or L;.NOT req-,ired; '"aVkSC-24 cask S-R -'"e required. then contact the Point Beach Dr', Fuel Storage group supervisor.
A Regulator. Commitrnent (CLB Commitment Database) change is El required or ',,NOT required If2 Rec'ila:or.
Commiunent Change is required, initiate a commitment change per NP 5.1 7.
A 0hange to the VSC-24 10 Cr-R 72.212 Site Evaluation Report is El required orZ .NOTrequired ifaVS'C-24 10 CFR 72.212 Site Evaluation Report change is required, then contict the Point Eea2h DrY Fuel Scerae-.g ,t' supervisor.