IR 05000302/1998002

Insp Rept 50-302/98-02 on 980126-30.Violations Noted.Major Areas Inspected:Operations,Maint & Engineering.Emergency Operating Procedures Were Also Reviewed

ML20248L618
Person / Time
Site:	Crystal River
Issue date:	03/13/1998
From:	Jaudon J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20248L615	List: IR 05000302/1998002 ML20248L612 ML20248L617
References
50-302-98-02, 50-302-98-2, NUDOCS 9803230288
Download: ML20248L618 (39)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION II

EMERGENCY OPERATING PROCEDURES TEAM INSPECTION Docket No.: 50-302 License No.: DPR-72

' Report No.: 50-302/98-02

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Licensee: Florida Power Corporation Facility: Crystal River 3 Nuclear Station Location: 15760 West Power Line Street Crystal River Florida Dates: January 26 through 30. 1998 Team Leader: W. Rogers Sr. Reactor Analyst Division of Reactor Safety i

In.spectors: J. Bartley, Resident Inspector, Division of Reactor Projects i l P. Harmon, Sr. Reactor Inspector, Division of Reactor Safety L. Mellen. Sr. Reactor Inspector Division of Reactor Safety l l ,

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Approved by: //s @

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i Mudon, Oltrecjlor' . Date Signed DivisionofRea(torSafety

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p 9803230288 980316 DR ADOCK 050003 2

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L EXECUTIVE SUMMARY l

l Crystal River Nuclear Plant. Unit 3 l NRC Inspection Report 50-302/98-02 A team of three regional inspectors and one resident inspector followed up on.

, significant outstanding issues from the previous emergency operating procedures (EOP) inspection, as documented in NRC Inspection Report 50-302/97-

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12. and performed a larger sampling of recently ccmpleted engineering calculations to su) port E0P actions. The inspection guidance was Inspection

, Procedure 42001. " Emergency Operating Procedures."

Doerations

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Through additional justifications or procedure revisions, the licensee satisfactorily resolved the deviations from the Technical Bases Document

(TBD) impacting the mitigation strategy documented in Inspection Report 50-302/97-12. (Section 03.1)

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The licensee and the team identified additional deficiencies with the procedural guidance used for in-plant E0P actions. These errors indicated a continuing lack of adequate verification and validation (V&V) activities for in-plant E0P actions. Corrective actions to previously identified errors in the procedural guidance for in-plant E0P actions were inadequate and an example of a violation of 10 CFR 50.

i Appendix B. Criterion XVI. Corrective Action. However, the V&V l

performed for those actions considered optional or with alternate paths due to radiological dose consequences was adequate. (Section 03.2)

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E0P actions identified in the TBD Cross step document, as being performed under the guidance of the Technical Support Center, were l proceduralized. Applicable personnel were trained on the new procedural

guidance. (Section 03.3)

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Notwithstanding the development of strategies for chemistry personnel to perform designated E0P actions due to select electrical bus

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unavailabilities, the licensee appropriately corrected the previously l identified lack of support staff guidance in terms of staffing and

direction for mechanical maintenance and chemistry personnel. (Section

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03.4) )

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. There was no procedure guidance on how to install the reactor building )

! (RB) purge flow instruments and this was a violation of 10 CFR 5 (

l Ap)endix B. Criterion V Procedures. Instructions and Drawings. The l E0Ps were sufficient to mitigate the two simulated transients observed  !

by the team. However, there were select steps that warranted further l licensee review for possible revision. (Section 03.5)

. The operating crews were capable of mitigating the two transients  ;

presented by the team. However, there was an example of performance  !

inconsistent with an E0P step. The Operations Manager provided specific training for all operators on this matter. (Section 04.1)

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The training packages discussing the E0P. changes introduced during the l outage period were adequate. Operating crews were scheduled to complete l the training packages prior to assuming shift duties beyond Cold l Shutdown. (Section 05.1)

Maintenance

Corrective actions to evaluate whether or not maintenance activities l could affect in-plant E0P actions were appropriate. A reasonable time l period was specified for completing the corrective actions. (Section M3.1)

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A number of the recently issued calculations supporting E0P actions were inadequate, and a violation of 10 CFR 50. Appendix B. Criterion II.

! Quality Assurance Program. Other recently issued calculations contained l errors or weaknesses, but the conclusions of these calculations were i

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valid. The type of inadequacies and errors identified by the team indicated a lack of attention to detail in checking and verifying l calculations. (Section E1.1)

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The mission dose evaluation and validations for RB purge activities was inadequate and an example of a violation of 10 CFR 50. Appendix Corrective Action. Also, while trying to resolve previously identified l mission dose inadequacies, the licensee identified an error in the design a process of not revising affected calculations when the Core Operating Limits Report was revised. However, the radiological consequences to personnel involved in purging activities did not prohibit accomplishing these activities following a maximum hypothetical accident. (Section El.2)

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During at least two periods no procedural guidance existed to use the l Low Pressure Injection (LPI) crossover line with flow split between the l two LPI lines to mitigate the consequences of a loss of coolant i

accident. This method of long term core cooling was discussed in the topical reports accepted by the NRC for compliance to 10 CFR 50.46 and i Anendix K. Also, a recent change to the Updated Safety Analysis Report !

(FSAR) regarding the LPI crossover line method of long term cooling was !

inconsistent with these topical reports. The licensee did not recognize )

l that eliminating the LPI crossover feature, as discussed in the topical i reports, from procedures and the UFSAR was an Unreviewed Safety i Question, and an apparent violation of 10 CFR 50.5 Years prior, the

' licensee identified these inconsistencies to the topical re3 orts with the major barriers to 3roceduralizing the LPI crossover metlod being design limitations. T1e licensee failed to enact appropriate, timely corrective actions to these design limitations. (Section El.3)

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The licensee had sufficient data from component manufacturers to certify the High Pressure Injection pumps and related components for long term post-accident operation. While the licensee had adequate technical justification for operating in the piggyback mode, piggyback mode

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testing did not fully demonstrate satisfactory equipment performanc Of special concern was the LPI injection valves which would need to operate in a severely throttled condition. The valves were not designed

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for throttling and were not throttled during piggyback testing. This was a violation of 10 CFR 50. Appendix B. Criterion XI. Test Contro (Section E1.4)

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Reoort Details l Summary of Plant Status

Crystal River Unit 3 was in the process of heating up to normal l o)erating temperature and pressure, but the reactor was sub-critical during tie inspection perio Introduction

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The primary objective of this inspection was to follow up on significant

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outstanding issues from the previous emergency operating procedures (EOP)

inspection, as documented in Inspection Report 50-302/97-12 and to aerform a l larger sampling of recently completed engineering calculations whic1 supported E0P actions. Most of the issues ins

dated December 16, 1997, to the NRC.pected were discussed in a licensee letter I. Ooerations

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03 Operations Procedures and Documentation 03.1 Conformance to the Technical Bases Document (TBD) Insoection Scoce (42001)

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The team reviewed selected E0P revisions and revised technical justifications to determine whether the procedural guidelines affected the mitigation strategy as described in the Babcock and Wilcox (B&W)

Owners' Group E0P TBD (74-1152414 Rev. 8) and two owners' group ap) roved TBD changes which will be incorporated into the next revision. T1e team L selected the review sample based upon previously identified inadequacies discussed in Inspection Report 50-302/97-1 As a result of the numerous design changes being implemented and outstanding Technical Specification requests yet to be ap3 roved by the NRC Office of Nuclear Reactor Regulation (NRR). the team 3ased the review on the assumption that License Amendment Requests 210 (dated June 14. 1997) 214 (dated October 31 1997) and 218 (dated September ), would be acceptable to NRR without deviation. The team did not review the technical adequacy of the E0P actions dealing with boron precipitation control since the adequacy of the licensee actions in this area was being reviewed by NR Observations and Findinas

, The team determined that through additional justifications or procedure revisions, the licensee satisfactorily resolved the deviations from the TBD impacting the mitigation strategy documented in Inspection Report 50-302/97-12. Resolution to the specific examples discussed in Inspection Report 50-302/97-12 were:

. The licensee technically justified the continued use of the ECCS piggyback mode as discussed in Section E1.3 of this Inspection E _. - - - _ - - - - _ - - - - _ --- .------ --- - -------------------_--------_-- _ -------------- -- _ __ _ --.--_-.--- _ --

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l Repor TBD. LBLOCA Cooldown, step 3.0. directed securing HPI l when LPI flow of x" (the minimum flow for adequate core cooling <

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derived by the licensee) amount existed for. greater than 20 minutes. TBD Volume 3 identified that this was due to concerns l of: 1) increasing radiation levels in the auxiliary building (AB)

l during RB sump recirc while in the 31ggyback mode. 2) pump i

failure, and 3) possibly avoiding tie complex evolution of i switching to the piggyback mode. The licensee had removed this J guidance and opted for long term operation of the HPI. pumps in piggyback mode.

i . The licensee technically justified inserting TBD, LBLOCA Cooldown,

step 1.2, at a location different than specified in the TBD. The

! TBD step directed opening the LPI crosstie if only one LPI pump

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was available to ensure injection through both lines. The licensee provided adequate justification that the ECCS in the piggyback mode of operation could accomplish the intended mitigation strategy, unless the HPI pumps failed. TBD step was inserted into new Emergency Plan Procedure EM-225E, Guidelines for Long Term Cooling, dated 1/27/98. upon multi)le failures rendering the piggyback mode inoperable and an L)I pump operatin This new Emergency Plan Procedure, EM-225E, was added to step 3.107 of E0P-08, LOCA Cooldown. Revision 5. Interim Change 0 In addition the licensee revised the STA's Post-Trip / Transient Checklist contained within enclosure 3 of Administrative Instruction Al-505, Conduct of Operations During Abnormal and l Emergency Events, to include considering using the LPI crosstie if inadequate core cooling was observe . The licensee inserted actions to maximize makeup to the RCS as the first step in revision 6 to E0P-06. SGTR. This resolved the technically inadecuate justification for inserting site specific steps 3.1. 3.2 anc 3.3 between SGTR identification and determination that the reactor was trippe . The licensee resolved the inadequate technical justification associated with delaying the isolation of the EFWT steam supply from the affected OTSG by revising E0P-06. SGTR. The step to isolate the steam supply was moved from 3.45 or 3.46 to 3.2 which significantly reduced the time that this direct radiological release path could be availabl . The licensee technically justified re-energizing the CRD buses after de-energizing them while responding to an ATWS. Step 2. of E0P-02, VSSV. directed de-energizing the CRD system to insert control rods if the reactor 3rotection system failed. Step 2. directed re-energizing the ClD buses by closing 480 VAC supply p breakers. 3305 and 3312. The licensee completed an engineering evaluation of the one ES bus involved. the 4B0 VAC Aux Bus from the 3312 breaker. The evaluation showed that the bus would not overload with all the current loads connected.

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The team inquired as to how future additional electrical loads would be controlled. Originally, the licensee indicated that a temporary power procedure would provide appropriate control However, as the team began reviewing these controls, senior licensee management (independent of the team's concerns) suspended use of the temporary power arocedure. Some of the senior management concerns, as ver) ally expressed to the team, were consistent with the team's concerns regarding use of'this documen Consequently. the licensee stated no additional loads would be added without ap3ropriate design controls being use The team confirmed that tie calculation. log was annotated with the engineering analysis showing breaker re-closure as presently acceptable. The log was to be reviewed by cognizant engineering personnel, prior to implementing a design chang l

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The licensee revised E0P-03. Inadequate Subcooled Margin. by moving the direction to start an emergency cooldown if the HPI ,

l system was unavailable to step 3.4. This complied with TBD 1 Section III.B. Lack of Adequate Subcooling Margin, step i Conclusions '

Through additional justifications or procedure revisions, the licensee satisfactorily resolved the deviations from the TBD impacting the mitigation strategy documented in Inspection Report 50-302/97-1 .2 Verification & Validation (V&V) Guidelines Inspection Scooe (42001)

The team walked down selected in-plant operator actions to ascertain whether the actions could be completed as written. The walkdowns were in part to determine whether adequate corrective actions were 3erformed to previously identified procedural inadequacies for accomplis 11ng in-plant E0P actions discussed in Inspection Report 50-302/97-12. The walkdowns were also prompted by a recent licensee initiated precursor card regarding an error in a procedure ste) to perform an in-plant E0P action. Additionally, the team reviewed tie V&V records confirming that alternate success paths existed and could be accom)lished if radiation levels rendered the primary success path inaccessible as part of determining whether the corrective actions tc radiological mission dose inadequacies discussed in Inspection Report 50-302/97-12 were performe Observations and Findinas

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The team's observations and findings were that the licensee's corrective l actions to a previously identified error in the procedural guidance for in-plant E0P actions were inadequate as delineated below.

f On January 5.1998. during an SB0 simulator scenario, the team observed operators attempt to implement Enclosure 2 of Abnormal Procedure AP-770.

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Emergency Diesel Generator Actuation, when directed to by E0P-12. SB At step 2.3 the crew could not perform a reset of Relay EDG 86. stopping the recovery. The location and the alpha-numeric designator of the lockout relay were mis-stated in the procedure. The licensee initiated PC3-C98-0103 in response to these deficiencie As part of the evaluation of PC3-C98-0103, the licensee concluded that the AP-770 error happened when the procedure was revised to account for i'

a plant design change modifying the EDG circuit and EDG output breaker trip circui During the validation of the procedure licensee personnel associated with the V&V process recognized that this particular design change had been implemented. Consequently the AP writer requested and verbally obtained additional equipment nomenclature and location information from the field validators for inclusion into the 3rocedure which would incorporate the design change. The end result of tais verbal exchange was the incorporation of the incorrect information into the procedure. A final validation of the draft procedure was not performed. Therefore. the error was not identified until the simulator scenario was performe The resolution to PC3-C98-0103 was to correct the procedure error in AP-770 and to perform an extent of condition review. The extent of condition review was to review the final version of AP-770 against the draft versions used for field validation to ensure each step requiring operator field actions had a documented validation and no other discrepancies existed. The review was then independently re-)erforme Similar reviews were performed for the remaining APs. One otler discrepancy associated with an electrical bus location was identified in AP-770, and a typographical error was identified in AP-545. All these reviews were accomplished and the corrective actions initiated by January 10, 199 On January 27, 1998, during a in-plant training session, the instructor and a trainee identified that steps 3.43 and 3.46 of AP-770 referenced the wrong location of the EDG 1A and IB speed droop contro The licensee personnel involved initiated PC3-C98-059 During walkdowns the team observed other deficiencies. These deficiencies included equipment tag errors and inaccurate or incomplete equipment descriptions in the procedures. Specifically:

. AP-770. Emergency Diesel Generator Actuation. Enclosure 2. Failed EDG Recovery, step 2.3. item # 2 stated " Reset EDG 86 DG Lockout l Relay (119 ft AB EDG Control Room)." The step should have identified the location in the EDG Control Room as the "1B EDG Electric. Equip. Cab."

. AP-470. Loss of Instrument Air step 3.4 item #1 described valve DCV-177 as "A DH Outlet Control." The step should have identified the valve as "A DH Cooler Outlet Control."

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AP-470. Loss of Instrument Air, step 3.4. item #2 described valve DCV-178 as "B DH Outlet Control". The step should have described the valve as "B DH Cooler Outlet Control."

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AP-470. Loss of Instrument Air step 3.26 directed the SP0 to close valve ASV-53 "GS Desuperheater Outlet 150" The valve tag described the valve as "Desuperheater Outlet Iso." without the "GS" identifie Although minor, these discrepancies were not identified when the i licensee performed the extent of review as part of the corrective I actions to PC3-C98-010 I 10 CFR 50. Appendix B. Criterion XVI. Corrective Action, requires conditions adverse to quality be promatly identified and correcte Failure of the corrective actions to )C3-C98-0103 to identify an additional error in AP-770 and errors in other APs (conditions adverse to quality) is an exam)1e of Violation 50/302-98-02-01. " Inadequate Corrective Actions to Recently Identified Deficiencies Associated with 1 E0P Actions." of this requiremen In response to the collective NRC and licensee negative observations associated with in-plant E0P procedure steps, the licensee performed an i extent of condition walkdown of AP-770 and noted over 30 noun name i description differences. The licensee stated that further corrective actions to PC3-C98-0592 would be to perform a step-by-step review of all abnormal and emergency operating procedures to ensure plant equipment descriptions and locations were correct. This would include a field ,

walkdown of all accessible equipment and was targeted to be completed by '

March 13. 1998. Appropriate procedure changes would then be enacte The team did determine that the V&V performed for those actions considered optional or with alternate paths due to radiological dose consequences was adequat Conclusions The licensee and the team identified additional deficiencies with the procedural guidance used for in-plant E0P acitons. These errors '

indicated a continuing lack of adecuate V&V for in-plant E0P Corrective actions to previously icentified errors in the procedural guidance for in-plant E0P actions were inadequate and an example of a violation of 10 CFR 50. Appendix B. Criterion XVI. Corrective Actio l However, based upon the completed V&V packages. the V&V performed for those actions considered optional or with alternate paths due to radiological dose consequences was adequate.

03.3 TSC Procedures to Accomolish E0P Actions i Insoection Scope (42001)

l The team reviewed the licensee's corrective actions to develop TSC

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guidance for performing certain E0P actions. Previously, the licensee's TBD-Cross ste) documents justified the omission of certain actions from >

the E0Ps on t1e basis'that the TSC would provide the guidance required to perform the actions. The team independently' reviewed the TBD-Cross step document and identified which actions had been referenced fo performance by the TSC. The team compared this list to the newly developed guidance to ascertain whether the TBD steps were incorporated into TSC guidance. Also, the team reviewed completed training records on the new TSC guidanc ! Observations and Findinas The team's findings and observations were as follow . The newly. developed guidance included all the areas where the TBD-Cross step document credited TSC directio .

The guidance was in the form of revised and new EmerPency Plan procedures. TherevisedprocedureswereEM-225.Dutfesofthe Technical Support Center Accident Assessment Team and EM-225 Post-Accident Boron Concentration Management. The new procedures were EM-225A, Post Accident RB Hydrogen Control: EM-225C. Post Accident Monitoring of Reactor Building Temperature: EM-225D. Dry 0TSG Tube to Shell Delta T Monitoring and Control: and EM-225 Guidelines for Long Term Cooling.

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The training records indicated that Emergency Coordinators. TSC Accident Assessment Team members, and EOF Accident Assessment Team members completed the required reading training package on the EM series procedure Conclusions E0P actions identified in the TBD Cross step document, as being performed under the guidance of the TSC. were proceduralize Applicable personnel were trained on the new procedural guidanc .4 Sucoort Personnel Procedures Insoection Scoce (42001)

i The team reviewed the licensee's corrective actions to ensure

! a]propriate sup] ort personnel were available and capable of performing l

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t1eir assigned E0P actions. Previously, as documented in Inspection Report 50-302/97-12. the licensee failed to designate adequate mechanical maintenance and chemistry support staff to perform their assigned E0P action Observations and Findinas The team's observations and findings were as follow l l

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The' licensee issued' administrative controls specifying the. minimum ,

number and type of support personnel necessary to accomplish E0P actions j prior to the activation of the TSC (approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after i

. directing TSC activation) for the deficient organizations identified in Inspection Report 50-302/97-12. Specifically: i

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Section 3.3.4 of Administrative Instruction. AI-1500. Conduct of l

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the Chemistry and Radiation Protection Department, was changed in l l Rev. 29 dated 1/19/98, to require two radiation protection' ;

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. Section 4.2.1.3 of AI-600, Conduct of Nuclear Plant Maintenance, section 4.2.1.3 was changed in Rev. 58 dated 1/24/98, to require qualified personnel be available during off shift hours to gag MSSVs if necessar The licensee issued appropriate procedures to accomplish the assigned E0P actions for these organizations. Specifically:

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'. Administrative Instruction. AI-1505. Conduct of Chemistry during Abnormal and Emergency Events, was issued delineating those

! actions to be performed by chemists cross referenced to the-applicable E0P or A . Administrative Instruction. AI-1506. Conduct of Health Physics ,

during Abnormal and Emergency Events, was issued delineating those !

actions to be performed by health physics technicians cross referenced to the applicable E0P or A * Preventive Maintenance Procedure. PM-275. General Preventive Maintenance Work, was revised adding an Enclosure 6. Installation of MSSV Gag.

L Appropriate training to gag a MSSV was provided as indicated by the i content of the training material and the completed training records for January 26 - 28, 199 The licensee was continuing to develop strategies for chemistry personnel to perform designated E0P actions due select electrical bus l unavailabilities as corrective actions to PC3-C97-724 l

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L Conclusions I Notwithstanding the development of strategies for chemistry personnel to perform designated E0P actions due select electrical bus ,

L unavailabilities, the licensee appropriately corrected the previously identified lack of support staff guidance in terms of staffing and l direction for mechanical maintenance and chemistry personne .5 Select E0P Procedure Steos  :

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Insoection Scooe (42001)

L The team observed licensed operators respond to two simulated emergency y conditions developed by the team to test specific sections of the E0Ps.

l The team reviewed the operator responses to determine in part whether the E0P procedural steps could be accom)lished as written and were not confusing to the operators performing tie steps. Also. due to the team previously identifying inadequacies with post-LOCA hydrogen purge activities as documented in Inspection Report 50-302/97-12. the team

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reviewed the procedural direction to accomplish post-LOCA hydrogen l purging.

! Observations and Findinas The team's observations and findings were as follow The sole guidance for the I&C technicians to install the RB purge flow elements was step 1.6 of Emergency Plan Procedure EM-225A. Post Accident l RB Hydrogen Control. This step directed I&C technicans to obtain the l instruments from the warehouse and install them. EM-225A did not include information from the flow instrument's vendor manual. The vendor manual specifically required torquing the flanged connections to ensure a proper seal. Also, there was no specific guidance in EM-225A directing the I&C technicians to plug the power cord into the receptacle (standard 110V plug). Initially failing to do so would result in additional radiological dose to the operators because the flow l instruments require a 10 minute warm up tim CFR 50. Appendix B. Criterion V. Instructions. Procedures, and I

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Drawings, requires in part that activities affecting quality be prescribed by documented instructions or procedures appropriate to the circumstance. Failing to include the above mentioned information into l the flow instrument installation step is Violation 50-302/98-02-02.

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" Failure to Provide Adequate Instructions for Installation of LR-82 and 83-FE."

i The E0Ps were sufficient to mitigate the simulated transients. Howeve there were areas where it was not clear why the E0P steps were written the way they were, or the procedural direction might be confusing. * Step 3.99 of E0P-08. LOCA Cooldown, was to perform E0P-10.

l Enclosure 18. Control Complex Chiller Startup, which required the i

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PPO to start the control room HVAC chillers (if not in service).

This was a time critical step and was inserted after the PP0 was directed manipulate the CFT electrical breakers in the Auxiliary Building at step 3.98. The team questioned whether the V&V activities confirmed that the time critical actions of step 3.98 could be performed within the specified time limits and what was the rationale of placing the actions of step 3.98, a non-time critical activity, before the actions of 3.9 The licensee's V&V for these actions had assumed that step 3.98

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could not be performed, since it was not essential to the mitigation strategy. Consequently, the licensee independently performed a LBLOCA scenario challenging this portion of the procedure with the time critical chiller actions being performed within 62 minutes (80 minutes was the acceptance criteria).

. Step 3.100 of E0P-08. LOCA Cooldown, directed a specific flow l valve for throttling and maintaining LPI flow once ECCS suctions I were aligned to the RB sum). However, step 3.97 provided the i direction to transfer to tie ECCS suctions to the RB sump. The l team failed to understand why the two step would be separated by j manipulating the CFT breakers and starting the control room HVAC chiller . During a SGTR scenario the team noted that E0P-05. Excessive Heat Transfer, step 3.1 directed isolating the affected OTSG in response to a steam leak in the RB or an uncontrolled 0TSG pressure reduction. However, sub-steps 4 & 5 of the details portions of this step-directed isolating the ADVs and blowdown

. lines on both the affected and non-affected 0TSG.

! . Step 3.34 of E0P-06. SGTR. directed a 6 F/hr RCS cooldown if a OTSG's level indicated s12.5" indicating a dry OTSG. and the reactor coolant pumps were operating. This criterion was inserted for those situations when the OTSG tubes would continue to be cooled by the BCS while the shell would be cooled by ambient temperature losses. By establishing the 6 F/hr cooldown there would not be excessive stress between the shell and tubes of the dry OTS However., if the SGTR was in the " dry" OTSG there would be shell cooling as the leaking RCS fluid flashed to steam and passed through the OTSG and into the steam lines. As the RCS cooled down it could be depressurized. As the RCS depressurizes the driving force of the leak was reduced, which reduced the leak rate. Therefore, performing an RCS depressurization at the l fastest acce) table rate was the intent of the SGTR mitigation l strategy. T1e use of the 6 F/hr cooldown rate may be overly  ;

restrictive, and when to apply the appropriate cooldown rate may be confusin The licensee stated that the step sequences associate with E0P-0 LOCA Cooldown. ste) 3.97 through 3.100 would be evaluated for revision. Also, tie licensee provided internal correspondence indicating that additional training on RCS cooldown rates with a steam leak and a SGTR in the same OTSG was being recommended to training management. Review of licensee actions with these matters is Open Item 50-302/98-02-03. "EOP Enhancements."

I Conclusions There was no procedure guidance for how to install the RB purge flow instruments and was a violation of 10 CFR 50. Appendix B. Cirterion Procedures. Instructions, and Drawings. The E0Ps were sufficient to l

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l l mitigate the two simulated transients observed by the team. -However, l there were select steps that warranted further licensee review for l possible revision.

l l 04 Operator Knowledge and Performance 04.1 Doerator Performance in the Simulator Insoection Scooe (42001)

The team observed licensed operators respond to two simulated emergency

!. conditions developed by the team to test specific sections of the E0Ps.

l Non-licensed, in-plant operator actions were simulated by personnel in the simulator booth. The team evaluated operator Performance with respect to whether the procedures were followed t1e administrative controls of AI-505. Conduct of Operations During Abnormal and Emergency Events, were followed and whether management expectations were me Observations and Findinas The team determined that the operating crews were capable of mitigating the transients presented. Three party communications were routinely used by both operating crews and place keeping was adequate to maintain i control of the mitigation actions. Also, the crews adequately l implemented the required carry-over actions when the conditions were satisfied for entry into specific carry-over step There was one example of Performance inconsistent with an E0P ste '

i During a SGTR scenario, tie procedure reader did not direct a cooldown l of 130 F/15 minutes until the pressurizer's temperature decreased to l 520 F, as allowed by E0P-14. Enclosure 15. E0P Temperature Log. By I reducing the temperature a substantial RCS pressure reduction could be

! performed which would reduce the driving force of the RCS leak and the leakrate of the SGT In response the Operations Manager issued an " Operations Study Book i Entry" dated 1/28/98. to all operations personnel highlighting the 130 F/15 minutes cooldown rate and the reason for using i Conclusions ,

The operating crews were capable of mitigating the transients presented !

by the team. However, there was an example of performance inconsistent with an E0P step. The Operations Manager provided specific training for all operators on this matte Operator Training and Qualification 05.1 Trainina Records

, Insoection Scooe (42001)

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The team reviewed training ' records to determine whether licensed

personnel had been trained on selected aspects of recently changed E0P The changes . included step sequence changes, clarifications and explanations of procedural steps, and the insertion of " mission dose

cautions" in several E0P '

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b. Observations and Findinas

The team's observations and findings were:

* All operating crews were scheduled to complete the E0P training I

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packages arior to assuming shift duties in modes other than Mode j 5. Cold Slutdown.

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.The training packages were adequate.to provide training on the E0P

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changes intreduced during the outage period. A training package

! was primarily formal classroom training, with appropriate lesson plans and learning objectives. Since a high rate of E0P changes were expected to continue. future changes were to be addressed via

required reading packages. Training packages contained sufficient l

l detail to describe the change and the rationale therefore.

l . Changes addressing mission dose assessments occurred in Procedures

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E0P-03. 04. 07. 08, and 14. Some of the changes involved adding a statement of "if accessible" to several steps involving in-plant actions performed by technicians and non-licensed operators.

, These actions were considered optional or had alternate success- )

l paths if post-accident dose rates precluded performing the action.- '

! Since mission dose rates had not been calculated for all in-plant l actions, on-the-spot determinations for access to several areas during some accident scenarios were required. These actions were also identified by the phrase "if accessible" at the appropriate procedural step.

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Personnel performing local actions were trained on the techniques q L for conducting radiation level checks for the procedural steps '

! indicated. Also, training was given covering the alternate ste !

or paths on a short-term basis. This training was only adequate l in the short term since the E0Ps did not include specific guidance at those step locations to direct the operators to the appro)riate actions to take, and/or the consequences of not performing t1e ,

step. The licensee stated that an evaluation would be performed I to consider adding such guidance. This is Open Item 50-302/98-02- !

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04. " Radiological Mission Dose Consequences.'

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' l Conclusions

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The training packages, discussing the E0P changes introduced during the outage period, were adequate. Operating crews were scheduled to complete the training packages prior to assuming shift duties beyond ;

Cold Shutdow I

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08 Miscellaneous Operations Issues 0 (0 pen) IFI 50-302/97-12 03: Enclosure 17/18 Interaction During the performance of a simulator scenario on 12/9/97, the team observed the PPO performing the actions specified in E0P-14. Enclosure 18. Control Complex Chiller Startup, as directed by the control room operators. The PPO completed the enclosure and verified proper operation of the chille Subsequently the PPO was requested by the control room operators to perform step 17.8 of Enclosure 17. Control Complex Emergency ventilation, which required actions to align the chilled water source to the running fan. The.PPO opened the CHV-2 valve and closed the CHV-4 valve to complete the alignment. During the scenario activities, it was determined that if the alignment actions required in step 17.8 of Enclosure 17 (i.e., flow balancing) were not performed properly, the running chiller unit could trip. Additionally if the chiller unit was tripped in this manner, re-establishing chiller operation could require an additional 30 minute To preclude this negative interaction between the enclosures, the licensee provided specific training the non-licensed and licensed operators emphasizing the need to perform enclosure 17 entirely before proceeding to enclosure 18. The team reviewed the training records associated with this matter and determined the training was satisfactor The licensee recognized that this solution did not provide the optimum instructions to the operators for a number of non-design bases limited ventilation operating configurations. Consequently, the licensee stated that the best human-factored set of instructions for all operating configurations would be determined and the applicable enclosure (s)

revised. The licensee initiated PC3-C97-8564 to formulate and implement the corrective actions. This matter remains open pendin completing the analysis and revising the E0P enclosures). (g the licensee 08.2 (Ocen) VIO 50-302/97-12-01: Inadequate Implementation of TMI Action Item E0P Order Portions of the licensee's corrective actions associated with this violation were discussed in various sections of this Inspection Repor Corrective actions for example 1 of this violation were discussed in Section 03.4. example 2 in Section 03.3 and example 3 in Section 0 A complete evaluation of the licensee's corrective actions can not performed until the docketed response to the NOV issued in Inspection Report 50-302/97-12 is received and reviewed for adequac This violation remains ope .3 (Closed) IFI 50-302/95-08-03: E0P Update Program An NRC inspection of the licensee's E0P program was documented in Inspection Report 50-302/93-16. A number of discrepancies were

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identified and five violations were issued against the E0P program. The licensee developed a corrective action plan to address the deficiencie Through succeeding years the licensee identified problems with implementation of the corrective action plan. This IFI was initiated to re-evaluate the E0Ps following completion of the licensee's upgrade effor Through a sampling approach an NRC team inspected the E0Ps that resulted from the licensee's upgrade efforts, as documented in this and Inspection Report 50-302/97-12. Any deficiencies with the current E0Ps will be addressed in follow up activities to issues opened in this and Inspection Report 50-302/97-12. Therefore. this IFI is close II. Maintenance M3 Maintenance Procedures and Documentation M3.1 Controls for Maintenance in Proximity to In-Plant E0P Actions Insoection Scone (42001)

The team reviewed the status of the corrective actions to incorporate procedural controls to evaluate whether maintenance activities could affect E0P in-plant action Observations and Findinos The licensee established corrective actions to this omission in the work control process in PC 3-C97-7365. The planned corrective actions and their projected completion dates included:

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evaluating the interim identification and components controls by February 2. 1998

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evaluating whether the Nuclear Maintenance Manual Al-600, and other AI-601 series procedures should be revised by February 27, 1998

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providing a list of E0P components to operations, work control and configuration management by March 6,1998

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revising applicable compliance procedures to establish interim process controls for E0P and related equipment by March 6. 1998, and

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bench marking other facilities as to how they handled this situation by March 30, 199 Completion of these corrective actions is Open Item 50-302/98-02-0 Consideration of Obstruction of In-Plant E0P Actions by Maintenance."

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14' Conclusions Corrective actions to evaluate whether or not maintenance activities could affect in-plant E0P actions were appropriate to the circumstanc A reasonable time period was specified for completing the corrective action II Enaineerina El Conduct of Engineering E1.1 Calculations Sucoortina E0P Actions

) Insoection Scoce (42001) ,

The team reviewed several engineering calculations supporting E0P actions or set points. The samples reviewed were skewed to those recently issued. The team reviewed these calculations for accurac appropriate assumptions. and compliance with applicable standards. The applicable standards included: Instrument Society of America (ISA)

67.04, part II. as referenced by instrumentation and controls Design Criteria Instrument String Error / Set point Determination Methodology and ANSI 45.2.11, 1974, Quality Assurance Requirements for the Design of Nuclear Power Plants, Observations and Findinas The team's observations and findings were: 1 A number of the recently issued calculations to support E0P actions were inadequat (a) I-90-0023. Reactor Building Hydrogen Concentration Loop Accuracy Calculation. Revision 1. dated November 19, 1997 This calculation identified the point at which containment hydrogen concentration reached 3.5% as 28.6 day The licensee used the high side of the instrument inaccuracy range instead of the low side. .Once-this was corrected, the hydrogen concentration could be reached in 16 days, and the

' purge should be initiated at this point in order to assure that the Technical Specification flammability limit

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(Technical Specification basis 3.3.17.12) was not exceeded.

l Technical Specification Basis 3.3.17.12 stated that hydrogen purge or recombiner initiation was to begin when hydrogen concentration reached or exceeded the 4.1 volume percent flammability limit for hydroge Quality Assurance Requirements for the Design of Nuclear l

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Power Plants. ANSI 45.2.11. 1974. Section 3. Design Input Requirements. Subsection 3.2. Requirements, stated that the

- design input shall include but was not limited to:

Instrumentation and control requirements including indicating instruments. controls.and alarms required for i operation testing, and maintenance. Other re I such as type of instrument, installed spares range quirements of i measurement, and location of indications, should also be

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included. (requirement 16)

(b) M-97-0120. Stoke Time for DHV-42/43 for Boron Precipitation.

Rev. 1 dated November 1. 1997-This calculation changed the maximum opening acceptable stroke time for valves DHV-42 and 43 from 120 seconds to 107 seconds. The associated IST procedure acceptance criteria in Surviellance Procedure SP-3408. DHP-1A. BSP-1A and Valve Surveillance, and Surveillance Procedure SP-340E. DHP-1 BSP-1B and Valve Surveillance was not revised. The need to change the procedures was originally recognized but did not occur. The licensee's initial review of this, as documented in PC 3-C98-0663. indicated a mis-communication between the design engineer and the IST engineer occurred. The most recent stroke time data on the two valves revealed the ne more conservative, acceptance criteria was still me Quality Assurance Requirements for the Design of Nuclear Power Plants. ANSI 45.2.11. 1974 Section 4. Design Proces Subsection 4.1. General stated in part that design activities shall be prescribed and accomplished in accordance with procedures of a type sufficient to assure that applicable design inputs were correctly translated into procedure Subsection 4.5. Other Design Documents. stated in part that procedures shall be established for the preparation and control of test procedure (c) I-90-0013. Post Accident RB Hydrogen Purge Instrument Accuracy. Rev. 2. dated December 29, 1994 *

The licensee failed to include the ramifications of

' installing the flow elements inconsistent with the manufacturer's recommendations. The manufacturer's manual stated that there should be at least 20' pipe diameters of straight pipe upstream of the installed flow element There was less than 20 pipe diameters which required an additional inaccuracy factor to be included in the instrument uncertainty for the flow elements. This factor was not included in the calculatio Quality Assurance Requirements for the Design of Nuclear Power Plants, ANSI 45.2.11. 1974 Section 3. Design Input Requirements. Subsection 3.2. Requirements. stated that the l

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design input shall include but was not limited to instrumentation and control requirements including type of instrument, range of measurement, and location of indications. (requirement 16)

10 CFR 50. Appendix B. Criterion II. Quality Assurance Program, requires that a quality assurance program be established. This program shall be documented by written policies. 3rocedures or instructions and carried out in accordance with t10se document The licensee's Quality Assurance Program as described in the UFSAR listed ANSI 45.2.11, 1974 Quality Assurance Requirements for the )

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Design of Nuclear Power Plants, under the committed standard l The licensee's failure to perform the calculations discussed above consistent with ANSI 45.2.11, 1974 is Violation 50-302/98-02-0 "Recently Performed Poor Calculations."

2. Although the conclusions of the calculations were valid, other ,

recently issued calculations contained errors or weaknesses. A '

sampling of the problems identified were as follow The equations determining the sensing line density changes for pressure transmitters RC-147-PT & RC-148-PT were off by an order of magnitude in Calculation I-97-0015. RC Low Range Pressure Loop Accuracy. RC-147-PT & RC-148-PT. These errors were in the intermediate steps of the calculation and appeared to be typographical errors because the process '

error results were correct. Also, there was an atypical use of average density used in this calculation that required further discussion with the licensee to confirm its applicabilit .

The reason for using different degraded pump head percentages for various operating configurations in Calculation M97-0141. E0P Cooldown Pressure / Temperature Limits, was not readily apparent (requiring one of the calculation reviewers to adecuately explain to the team the rationale for using the two cifferent values).

. Calculation I-96-0002. SPDS TSAT Display Errors, used the Monte Carlo technique to " confirm the conservative nature of the calculations." However, the Monte Carlo technique was not an approved method and was less conservative than the approved ISA 67.04 method. After discussion with the licensee the team ascertained that the part of the calculation using the Monte Carlo method was not used for anything and was superfluous.

i .

The title of Calculation E-90-0023. Evaluation For

! Containment Spray Between pH of 4.0 and 12 5. was incorrec The calculation determined that materials within the l

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containment would remain functional during post-accident conditions involving low pH spray solutions. High pH

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conditions were not discussed since a design change implemented eliminated the containment spray's sodium hydroxide addition feature, and thus, the need to analyze for high pH effects. However, the title was not revised after the design change was implemente The licensee initiated PCS 3-C98-0647 and 643 to capture some of these and other calculational problems identified by the team for rectification at their next updat Conclusions A number of the recently issued calculations to support E0P actions were inadequate, and a violation of 10 CFR 50. Appendix B. Criterion I Quality Assurance Program. Other recently issued calculations contained errors or weaknesses, but the conclusions of the calculations were valid. The type of inadequacies and errors identified by the team indicated a lack of attention to detail in checking and verifying calculation El.2 Calculations Associated with RB Hvdrocen Puraina Scope The team reviewed the licensee corrective action documents associated l with post-LOCA hydrogen control errors and omissions identified during ]

Inspection Report 50-302/97-12. In the previous Inspection Report the team identified: 1) errors in Calculation M-93-0006 including time validation and the earliest post-accident time at which hydrogen purge might be required; and 2) a mission dose calculation was not performed for the I&C technicians installing the flow instrumentatio Observations and Findinos The team's observations and findings were: The licensee's post-LOCA hydrogen controls would be accomplished .

by RB purging. Temporary com]ressors would be hooked up to the RB !

ILRT system and the RB atmosplere purged through the RB purge filter Prior to purging. I&C technicians would install two flow '

elements in the ILRT purge lines and mount the local indicator These components were located in the same room as the RB purge filter bank and the AB ventilation filter banks. To initiate the i purge, system operators would operate multiple valves and dampers, several in the same area as the RB purge and AB ventilation system filter bank . In response to the previous team findings as to the earliest post-accident time at which hydrogen purge might be required, the licensee issued CSM-98-001. Case Study for Calculation M84-1004 revision 2. * Hydrogen Generation." This revised analysis did not adequately determine the time frame when the purge would be l

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! 18 require The case study result was 23 day As previously discussed, accounting for instrument accuracy, the earliest time

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to perform the purge would be 16 day . In response to the previous team findings as to the lack of a mission dose calculation for the I&C technicians installing the ,

flow instrumentation, the licensee performed a mission dose j evaluation along with time validations. Formalizing the dose l calculations was part of the long term corrective actions. The l mission dose evaluation and validations were inadequate as )

described belo .

The evaluation failed to account for the radiological dose I from the loading of the AB ventilation filter banks. The AB '

ventilation system maintains the ECCS rooms at a negative pressure (assuming off-site power availability) and thus filters all the ECCS component leakage, which may contain highly radioactive water from the RB sump. This omission also affected the dose calculations for the operator initiating RB purge as documented in Calculation M-93-000 .

The evaluation did not include a 50 gpm RHR pump seal leak (standard assumption and identified in UFSAR Chapter 14) in determining the potential radioactive loading of the AB filters

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The time validations did verify the time needed to carry the equipment up two flights of stairs (-30 foot vertical rise).

The licensee used their standard thirty feet-per-minute numbe This was non-conservative for two people carrying a cart with approximately 50 pounds of equipment on i Based on the general doses for the stairs. the change to the mission dose was negligibl CFR 50. Appendix B. Criterion XVI. Corrective Action. requires conditions adverse to quality be promptly identified and corrected. Failure of the corrective actions to adequately evaluate the radiological mission dose associated with installing the RB purge flow instruments is identified as Violation 50-302/98-02-01. " Inadequate Corrective Actions to Recently Identified Deficiencies Associated with E0P Actions." The team's independent assessment of radiological dose consequences, although higher than the licensee's evaluation. was that the surging activities could be accomplished to control post-accident 1B hydrogen concentrations for the maximum hypothetical l accident.

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! In the process of resolving the lack of radiological mission close evaluations for in plant E0P actions. the licensee determined that j the radiological source term used for the few existing dose

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! 19 calculations. such as for purging the RB were not conservative by l ~ 7%, as documented in PC3-C97-863 In the past the fuel cycle period had been increased from 12 months to 24 months which increased the source term. Evidently when the design bases document, the Core Operating Limits Report, was revised the affected calculations were not. This indicated an error in the design control process. The licensee indicated that the additional 7% source term increase was included in the new mission dose evaluation Conclusions:

The mission dose evaluation and validations for RB purge activities were inadequate and an example of a violation of 10 CFR 50. Appendix Corrective Action. Also, while trying to resolve the previou:ly identified mission dose inadequacies the licensee identified an error in the design control process of not revising affected calculations when the core operating limits report was revised. However, the radiological consequences to personnel involved in purging activities did not archibit accomplishing these activities following a maximum hypothetical acciden El.3 Low Pressure Iniection Crossover Mode of Ooeration Insoection Scooe (42001)

Since the licensee did not direct using the crossover mode of LPI operation in the E0Ps. the team began reviewing the licensing basis documents for long term core cooling following a LOCA as documented in Inspection Report 50-302/97-12. The applicable regulatory requirements for long term core cooling are discussed in 10 CFR 50.46 and 10 CFR 5 .

Appendix K. During this inspection period, the team completed this !

review. Documents reviewed included B&W topical reports. the licensee's FSAR. a safety evaluation to change the current FSAR and applicable correspondence. Also, the team reviewed the NRC's SERs associated with ECCS with respect to long term core coolin Observations and Findinas The team's observations and findings were as follow . During at least two time periods after the operating license was granted. there was no procedural guidance to use the LPI crossover line with flow split between the two LPI lines (the crossover line method of long term core cooling, option #1 in BAW 10103A and BAW 10104) to mitigate the consequences of a LOCA. The first time period was from July 1979 until June 1989. The second time period was May 2. 1996. until the issuance of Procedure EM-225E.

l Guidelines for Long Term Cooling on January 27. 1998. EM-225E i

was issued, due to the NRC E0P inspection team identifying the

[ lack of such a procedure to the licensee in December 1997.

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l Originally, depending upon plant conditions. the licensee used the l

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crossover line method of long term core cooling in two procedure The procedures were EP-106. Loss of RC/RC Pressure, and OP-404 Decay Heat Remova In 1979. both procedures were revised such that EP-106 referenced OP-404 and in Revision 24 dated July , of OP-404 the use of the crossover line method was delete In June 1983. the licensee instituted the first set of symptom based procedures for dealing with transients and accidents with AP-380. Engineered Safeguards Actuation, superseding EP-106. In Revision 20. dated June 29. 1992, of AP-380. a new step 3.8 was added directing use of the crossover method if an LPI pump was unavailable. Also, Revision 73. dated June 12. 1989. of OP-40 re-instituted the use of the crossover line with flow in both injection lines provided there was adequate subcooled margin in section 4.13. In Revision 83. dated March 4. 1992, to OP-404. the use of the crossover line method of core cooling was transferred to section 4.12. However.. step 3.8 to AP-380 was deleted in Revision 22 on April 8. 1993 and, section 4.12 to OP-404 was revised on May 2.1996, in revision 101. Revision 101 removed the crossover method, along with the deleting the pressurizer auxiliary spray as a boron precipitation control metho Therefore, for a second time period. May 2.1996, until the NRC E0P inspection identified the issue to the licensee in 1997, there was no procedural guidance on using the crossover line method of long term core coolin Section 6.1.2.12. Low Pressure Injection, in the licensee's UFSAR stated "The LPI System is provided with a crossover line to permit one LPI string flow of 3.000 gpm to be split equally. thus providing a minimum of 1.500 gpm flow to both core flooding injection nozzles simultaneously should a core flooding line or one LPI pump fail. Redundant transmitters and indicators are provided for LPI flow measurement and indication. The LPI crossover injection mode of operation is accomplished by opening the crossover line, provided with a two-way flow element between the separate and independent LPI strings, and remotely adjusting the flow through the crossover line to 1.500 gpm via two (one in each LPI string) electric motor operated valves (see Figure 9-6)."

i Section 14.2.2.5.4. ECCS Qualification, stated that. "In order to l qualify the ECCS. the NRC placed requirements on the ECCS to  !

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ensure that the health and well being of the public is not '

im) acted. These requirements are specified in 10 CFR 50.46 and 10 CFR 50. Appendix K. The criteria contained in Part 50.46 are i l

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-applicable to all sizes of LOCAs and are necessary in order to verify adherence. These criteria are as follows . A path to long-term cooling must be established." This section further stated that BAW-10104. Rev. 3. was the methods report on how the computer model used to ensure compliance with 10 CFR 50.46 would  !

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be assembled and run. Also, the "The LBLOCA application report for the 177 FA lowered loop plants is BAW-10103A."

Topical Report BAW-10103A. Rev. 3. "ECCS Analysis of B&W 177-Fuel Assembly Lowered-Loop NSSS." and Topical Report BAW-10104. Rev. "ECCS Analysis Of B&W's 177-FA Lowered-Loop NSS." discussed use of l the LPI crossover in Chapter 10. Long-Term Cooling. Section 1 stated in part that "Several alternate modes of operation of the ECC systems can be used during long-term cooling, if necessary, while maintenance is being performed on normal equipment: One LPI pump operating with crossover line valves open: flow s split between the two LPI lines by the control valve . Each LPI string operating and the LPI pump in each LPI string operating and pumping through its own injection lin . One LPI pump operating with injection through its associated injection line and with the crossover to the associated HPI string open: the associated HPI pump would be pumping through its HPI lines."

Section 10.2 further stated, in part. "With either of the two LPI pumps operable. ECCS injection flow can be maintained through two flow paths."

The licensee failed to recognize that procedurally eliminating the LPI crossover feature was an Unreviewed Safety Question (US0).

One of the definitions of an US0 is that the proposed change increases the consequences of an accident or malfunction of equipment important to safety previously evaluated in the safety analysis report. The proposed change could potentially increase the consequences of a loss of coolant accident by reducing the number of procedurally available long term cooling methods of BAW-10103A. Rev. 3 and BAW-10104. Rev. 3 from three to two (the three methods were discussed in #1.B. above). By decreasing the number of credited long term cooling methods for reducing core damag the potential radiological consequences of a loss of coolant accident were increased. Also. the consequences of a failed HPI pump would increase since there would only be one, not two, other acceptable long term core cooling methods availabl CFR 50.59 Changes, tests and experiments. (a)(1) states in part that "The holder of a license . . may make changes in procedures as described in the safety analysis report . without prior Commission approval unless the proposed change involves an unreviewed safety question." Failing to receive NRC approva for these procedural changes (Revision 101 to OP-404 on 5/2/96 and Revision 24 to OP-404 on 7/3/79) were examples of apparent violation EEI 50-302/98-02-07 " Inadequate LPI Crosstie Safety Evaluations." of 10 CFR 50.5 _ _ _ _ _

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22 A recent change to the UFSAR. describing the LPI crossover method of long term core cooling following a LOCA. was not consistent with the topical reports accepted by the NRC for compliance with 10 CFR 50.46 and 10 CFR 50. Appendix Prior to the initial licensing of Crystal River, a number of issues arose regarding the ECCS performance evaluation. Earlier versions of To)ical Report BAW-10103A. BAW-10104 and BAW-10064

"Multinode Analysis of Core Flood Line Break for B&W 2568-MWt Internal Vent Valve Plants." made up a part of the applicant's method of showing compliance with 10 CFR 50.46 and 10 CFR 5 A)pendix K. In NRC SER supplement 3. 12/30/76. the NRC concluded t1at the method used by B&W in calculating the fuel cladding temperature during the blewdown oh6se did not conform to the requirements of 10 CFR 50. Appendix K. This directly impacted BAk-10064. which was a computer analysis that essentially terminated once ECCS flow (via an HPI pump and the intact core flood tank) exceeded the boil-off rate. Therefore, the analysis terminated within a half hour of accident initiatio Subsequently. B&W properly performed the analysis and submitted it as Appendix C to BAW-10103. Rev. 3, which was accepted by the NR The new analysis also terminated once the ECCS exceeded the boil-off rate (within 20 minutes of accident initiation). Therefore, the NRC accepted Topical Report BAW-10103A. Rev. 3. "ECCS Analysis of B&W 177-Fuel Assembly Lowered-loop NSSS." and Topical Report BAW-10104. Rev. 3. "ECCS Analysis Of B&W's 177-FA Lowered-loop NSS." as the method and applications for complying with 10 CFR 50.4 Never was the applicability of the long term core cooling methods described in the original versions of BAW-10103 and 10104 an issue. The original SER of July 5.1994, stated in part "The low pressure injection system lines are equip)ed with a crossover line inside the auxiliary building so that eac1 LPIS pump is connected to both core flooding tank (CFT) nozzles on the reactor vesse Manually operated valves in the crossover line will be arranged so in the unlikely event of the simultaneous occurrence of a break at the worst location in a CFT line and the loss of one LPIS. half of the flow of the other LPIS pump will reach the reactor pressure vessel to insure adequate long term core cooling."

On January 2.1998, the licensee's onsite review committee, the Plant Review Committee, approved a safety evaluation completed the day before authorizing a change to the UFSAR. The UFSAR change was FSAR6-R24-33 and concluded that no unreviewed safety question l existed. The UFSAR change revised a portion of section 6.1.2.1.2.

l Low Pressure Injection, and inserted a new section. 6.1.3. Core Flood Tank (CFT) Line Break SBLOCA. The section 6.1.2. revision did not address the use of the LPI crossover if a core flood tank line failed and/or one LPI pump failed due to plant specific design limitations. The new section 6.1.3.1.3 discussed t1e CFT line break consistent with BAW 10103 Rev. 3. Appendix C.

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L 23 In this latest 50.59 safety evaluation the licensee misinterpreted a statement in 10103. Appendix C. as somehow negating long term cooling section 10 of BAW-10103 and 10104. This statement wa "In this particular transient, long-term cooling is initially established by using one HPI pump. No LPI or CFT injection took place since the system pressure was above the injection actuation

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pressures. Thus, it is concluded that for breaks less than or equal to 0.04 ft2 the HPI alone is capable of matching decay heat boil-off and maintaining a liquid inventory sufficient to preclude any cladding temperature excursions." This statement is true in that once reflood is com)leted (this takes a matter of minutes).

HPI would initially be tie long term cooling method, but it would-not be the exclusive method as discussed in the original SE Once RCS pressure decreased below 500 psig. LPI would be actuated by Engineering Safety Features and, at 300 psig begin to inject into the reactor vessel. As previously stated, this computer analysis terminated in minutes and prior to initiation of long term cooling via recirculation from the reactor building sum Also, the consideration of using the crossover lines when an LPI pump would fail during long term cooling following a LBLOCA was not discusse The licensee failed to recognize that procedurally eliminating the

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LPI crossover feature following a core flood tank line break or failure of an LPI pump was an Unreviewed Safety Question (US0).

One of the definitions of an US0 is that the proposed change increases the consequences of an accident or malfunction of equipment important to safety previously evaluated in the safety analysis report. The proposed change could potentially increase the consequences of a loss of coolant accident by reducing the number of procedurally available long term cooling methods of BAW-10103A. Rev. 3 and BAW-10104. Rev. 3 from three to two (the three methods were previously discussed). By decreasing the number of credited long term cooling methods for reducing core damage, the potential radiological consequences of a loss of coolant accident were increased. Also, the consequences of a failed HPI pump would increase since there would only be one not two, other acceptable long term core cooling methods availabl CFR 50.59 Changes, tests and experiments. (a)(1) states in part that "The holder of a license . . may make changes ... in the safety analysis report . . . without prior Commission approval, unless the proposed change . involves ... an unreviewed safety question." Failing to receive NRC approval for this change is an example of apparent violation EEI 50-302/98-02-07. " Inadequate LPI Crosstie Safety Evaluations." of 10 CFR 50.5 . Years prior to the recent NRC E0P inspection, the licensee identified the inconsistency between the lack of procedural l guidance and the topical reports and the UFSAR. On April 27, 1995. Problem Report 95-0083 stated that the FSAR and the LPI Engineering Design Bases Document assumed the capability to

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perform the LPI crossover injection mode of operation but, no l

' procedural guidance existed to implement this mode of operatio On Marcy 13. 1997. PC3-C97-2241 was issued re-iterating the lack of procedural guidance for the crossover mode of operatio . As identified in these conditions adverse to quality re] orts, the major barriers to having procedures which utilized the _PI crossover method were design limitations. These included the inability to withstand all single active failures and still accomplish the core cooling function. WiththeLPIinjection valves. DHV-5 and 6. *normally closed" an electrical bus failure rendering the LPI pump and the applicab.le valve in the non-faulted CFT line inoperable would prohibit injection to the reactor vessel. Other limitations included not being able to use the boron precipitation controls while in LPI crossover, there was a restrictive number of control manipulations allowed on setting the position of the LPI injection valves and the original crossover flow instrumentation was not certified as a type A Regulatory Guide 1.97 variable. Also, the licensee considered it necessary to operate essentially in piggyback and LPI crossover while taking suction from the RB sump, when transitioning to LPI crossover. In this condition the flow demands on the LPI pump would be very close to the calculated available net positive suction hea The single failure limitation associated with the LPI crossover mode of long term core cooling requires further NRC evaluation and is unresolved item URI 50-302/98-02-08. "LPI Crossover Cooling Non-Single Failure Proof."

5. When the NRC began this E0P inspection, corrective actions to insert the LPI crossover mode into procedures had not been accomplished and were not scheduled for com)letion until months after the unit restarted. This indicated tlat the licensee failed to enact appropriate, timely corrective acticqs to these design limitation (a) Under the root cause analysis section of the Problem Report 95-0083 the evaluator stated in part . "CR3 is a HOT SHUTDOWN plant, and as such, does not need to provide for long term cooling except as required for compliance with 10 CFR 50.54 and Appendix K. . . ." Nowhere in the topical reports accepted by the NRC was this " Hot Shutdown" distinction discussed. Chapter 10 of BAW 10103A and BAW 10104 stated in part. "The duration of long-term cooling is the period between the onset of long-term cooling and the end of core cooling requirement The exact duration of long-term cooling will var A realistic assessment of

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the duration for the worst case is approximately one month." l Therefore, this discussion in the root analysis section was not supportabl (b) The projected corrective actions to Problem Report 95-0083

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l included revising the LPI Engineering Design Bases Document, certifying the crossover flow instrumentation to Regulatory Guide 1.97 standards for a type A variable. completing the ,

applicable hydraulic and instrument uncertainty I calculations. making valves DHV-5 and 6 "normally open." and revising the necessary plant procedures to allow using the crossover mode of operation. These corrective actions were to be completed by July 1, 199 ;

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'(c) In PC3-C97-2241 it was stated that implementation of Problem Report 95-0083 was unnecessary prior to unit restar I Restart Panel meeting minutes indicated that this rationale was based upon Framatome (formerly B&W) analysis demonstrating the LPI crossover mode provided abundant rather than adequate core coolin Conclusions-During at least two periods after the o)erating license was granted. no procedural guidance existed to use the _PI crossover line with flow s) lit between the two LPI lines to mitigate the consequences of a LOC T11s method of long term core cooling was discussed in the topical reports (the crossover line method of long term core cooling. chapter 10. option #1 in BAW 10103A and BAW 10104) accepted by the NRC for compliance with 10 CFR 50.46 and Appendix K. Also, a recent change to the UFSAR regarding the LPI crossover line method of long term cooling was inconsistent with these topical reports. The licensee failed to recognize that eliminating the LPI crossover feature, as discussed in the topical reports, from 3rocedures and the UFSAR was an US0. and an apparent violation of 10 C:R 50.59. Years prior to this inspection, the licensee identified these inconsistencies to the topical re) orts with the major barriers to 3roceduralizing the LPI crossover metlod being design limitations. T1e licensee failed to enact appropriate, timely corrective actions to these design limitation El.4 ECCS Piaavback Mode of Ooeration

, Insoection ScoDe (42001)

Due to the licensee directing unrestricted HPI operation in piggybac the team identified that the HPI pumps had not been purchased consistent i with this mode of operation as documented in Inspection Report 50-302/97-12. During this inspection period the team evaluated the engineering analysis justifying the unrestricted use of the HPI pumps in piggyback as directed by the E0Ps. The team reviewed the technical analysis of other components associated with the piggyback mode. In addition the team evaluated previous test results to determine whether a test program had been established to demonstrate that the equipment would perform satisfactorily in this mode of operatio Observations and Findinas

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The team's observations and findings were: The licensee documented the suitability evaluation of HPI equipment for long-term post-accident operation in the piggyback

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i mode in OCR 98-0003. The OCR was typically thorough and documented correspondence with the various component vendors and the licensee engineer's evaluation. The OCR evaluated the various areas of concern (small debris, increased component doses. long term component temperatures) and included all pump component HPI Control Valves. HPI Discharge Stop Check Valves, and HPI Pump Recirculation Orifices. The OCR concluded that the HPI equipment was operable but not fully qualified. The licensee's long term corrective action was to prepare a Deficiency Report (DR) to document qualification of the HPI equipment for long term operation in the piggyback mod . The OCR referenced that pre-operational testing of the piggyback mode was done, but it did not identify that the testing was not in the lineup for LOCAs which cause the RCS to depressurize to allow LP In the pre-operational test the LPI injection valve. DHV-5 or DHV-6 (depending upon which train was being tested) was closed and the LPI pump output was being supplied only to the suction of the HPI Jump. The HPI injection flow was set at 300 gpm. The E0P piggybacc configuration was with the LPI pum gpm and supplying ~600 gpm to the HPI pumas.ps The HPIinjecting injectionat -2200 flow would then be ~600 gpm. Also, to aclieve ~2200 gpm LPI flow the LPI injection valve needed to be throttled to at least 95%

close . The OCR Jackage was adequate to justify technically long term piggybacc operation in the E0Ps. However, the package was weak in select areas as discussed belo . MOVATS testing results performed per Performance Test Procedure PT-421 demonstrated that DHV-5 and 6 could throttle down to flows of ~1500 gpm in an injection lineup. However, the test did not direct the operators to take any data or observe for flow instabilities on the injecting lin Also, the test did not provide any flow to the suction of the HPI pumps which may affect the system's flow stabilit . Correspondence from the valve manufacturer. Crane, did not recommend using gate valves, let alone 10" gate valves. such as DHV-5 or 6. as throttle valves. The manufacturer indicated that it would "very likely result in significant flow induced disc vibration." Also, with either valve closed approximately 95%.

small changes in the wedge position would cause large changes in flow making it very difficult to position the wedge in the desired location. However. the manufacturer stated that it was

"very unlikely that it would cause major structural damage resulting in the disc separating from the stem or prevent the valve from being operated.

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27 In response to the potential problems in positioning the wedge, the licensee incorporated a flow resistance curve for similar valves into the simulator modeling for the valves of concern. The valves' flow characteristics were modeled as a linear function l between 90 and 100% closed which was not totally consistent with the flow resistance curve, especially in the area of concern, approximately 95% shut. During a simulator scenario, the o)erating crew established the necessary LPI flow by throttling DiV-6 using the 90-100% closed linear flow resistance curv . 10 CFR 50. Appendix B. Criterion XI. Test Control, requires a test program, including operational tests, be established assuring that structures, systems, and components will perform satisfactorily in service. The licensee's failure to establish a test program demonstrating the flow stability of the ECCS piggyback mode is Violation 50-302/98-02-09 " Inadequate Piggyback Testing." Conclusio_n_q The licensee had sufficient data from component manufacturers to certify the HPI pumps and related components for long term post-accident operation. While the licensee had adequate technical justification for operating in the piggyback mode, piggyback mode testing did not fully demonstrate that the equipment would aerform satisfactoril Specifically, the flow stability of t1e piggyback mode had not been demonstrate Of special concern was the LPI injection valves which would need to operate in a severely throttled condition. The valves were not designed for throttling and were not throttled during piggyback testin This was a violation of 10 CFR 50. Appendix B. Criterion X Test Contro E8 Miscellaneous Engineering Issues E8.1 Uodate Final Safety Analysis Reoort Omission While reviewing the information on the CFT SBLOCA the team could not identify any discussion of the insert located within the CFT line that reduces a break of this line to 0.44 ft' The team confirmed through a review of drawings that the flow restricter was installed in the entrance of the common CFT/LPI line to the reactor vessel and the inner dimensions of the restricter conformed to the SBLOCA computer analysi After the team identified this UFSAR omission the licensee initiated PC 3-C98-048 E8.2 (Closed) URI 50-302/97-12-06: Previous LPI Crosstie Safety Evaluations This matter was elevated to an example of an apparent violation EEI 50-302/98-02-07. " Inadequate LPI Crosstie Safety Evaluations." in Section E1.3.b.1. Therefore, this URI is close E8.3 (Closed) URI 50-302/97-12-07: Current LPI Crosstie Safety Evaluations

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L L This matter was elevated to an example of an apparent violation EEI 50-302/98-02-07 " Inadequate LPI Crosstie Safety Evaluations." in Section

.E1.3.b.2. Therefore, this URI is close E8.4 (Closed) IFI 50-302/96-04-03: Effect of Set Point Calculations on E0P Revisions This IFI was'to review the licensee's E0P Set point calculations due to significant changes in the E0Ps. As documented in this and Inspection Report 50-302/97-12. an NRC inspection team. using a sampling approac reviewed select calculations supporting E0P set points. -Any deficiencies with the current E0Ps will be addressed in follow up activities to issues opened in this and Inspection Report 50-302/97-1 Therefore. this IFI is close IV. MANAGEMENT MEETINGS X1 Exit Meeting Summary The team leader discussed the progress of the inspection with licensee representatives on a daily basis and presented the inspection results to members of licensee management and staff listed below at the conclusion of the inspection on January 30. 1998. The licensee acknowledged the findings presented. At the exit the team leader asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

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PARTIAL LIST OF PERSONS CONTACTED

. LICENSEE:

J. Baumstark. Director. Quality Programs

G. Becker. E0P Project

T. Catchpole. Nuclear Licensing

R. Davis. Assistant Plant Director. Operations L. Gagne. E0P Project

R. Grazio. Director. Regulatory Affairs

S. Greenlee. Manager Nuclear Operations Engineering

• B. Gutherman E0P Project

D. Herrin. Nuclear Compliance

B. Hickle Restart Director

J. Holden. Site Director M. Kelly. E0P Project

J. Lind. Manager Nuclear Operator Training

C. Pardee. Director Plant Operations

C. Pellerin. E0P Project

D. Porter. E0P Project

• K. Rass. E0P Project

M. Rencheck. Director. Engineering

T. Taylor. Director. Nuclear Training

R. Widell. E0P Project NRC:

S. Cahill. Senior Resident Inspector

P. Harmon RII

L. Mellen RII

J. Bartley, RII

• W. Rogers RII

• personnel present at the 1/30/98 exit LIST OF INSPECTION PROCEDURES USED IP 42001 Emergency Operating Procedures LIST OF ITEMS OPENED 50-302/98-02-01 VIO Inadequate Corrective Actions to Recently Identified Deficiencies Associated with E0P Actions. (Sections 03.2.. E1.2.)

50-302/98-02-02 VIO Failure to Provide Adequate Instructions for Installation of LR-82 and 83-FE (Section 03.5)

50-302/98-02-03 IFI E0P Enhancements. (Section 03.5)

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t 30 50-302/98-02-04 IFI Radiological Mission Dose Consequences. (Section 05.1)

l 50-302/98-02-05 IFI Consideration of Obstruction of In-Plant E0P Actions by Maintenance. (Section M3.1)

l 50-302/98-02-06 VIO Recently Performed Poor Calculations. (Section El.1)

50-302/98-02-07 EEI Inadequate LPI Crosstie Safety Evaluations.

, (Section E1.3)

50-302/98-02-08 URI LPI Crossover Cooling Non-Single Failure Proo (Section E1.3)

50-302/98-02-09 VIO Inadequate Piggyback Testing. (Section E1.4)  !

LIST OF ITEMS CLOSED 50-302/97-12-06 URI Previous LPI Crosstie Safety Evaluation (Section E8.2)

50-302/97-12-07 URI Current LPI Crosstie Safety Evaluation. (Section E8.3)

50-302/95-08-03 IFI E0P Update Program (Section 08.3)

50-302/96-04-03 IFI Effect of Set Point Calculations on E0P Revisions (Section E8.4)

Lift OF IT.fMS STATUSED 50-302/97-12-03 IFI Enclosure 17/18 Interaction. (Section 08.1)

50-302/97-12-01 VIO Inadequate Implementation of TMI Action Item E0P f Order (Section 08.2)

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Appendix B i

List of Acronyms Used AB Auxiliary Building ACRS Atomic Concerns and Reactor Safety ADV Atmospheric Dump Valve AI Administrative Instruction ANSI American National Standards Institute AP Abnormal Procedures ATWS Antici]ated Transient Without Scram B&W Babcocc and Wilcox BSP Building Spray Pump CFR Code of Federal Regulations CFT Core Flood Tank CHV Chilled Water Valve Crystal River

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CR -

CRD Control Rod Drive DG Diesel Generator DH Decay Heat DHP Decay Heat Pump DHV Decay Heat Valve ECC Emergency Core Cooling  ;

ECCS Emergency Core Cooling System  !

EDG Emergency Diesel Generator ,

EEI Escalated Enforcement Item '

EFW Emergency Feedwater i EFWT Emergency Feedwater Turbine E0P Emergency Operating Procedure ES Engineered Safeguards ESF Engineered Safeguards Features FE Flow Element FPC Florida Power Corporation 4 FSAR Final Safety Analysis Report '

GS Gland Sealing HPI High Pressure Injection HVAC Heating, Ventilating and Air-conditioning I&C Instrument and Control IFI Inspector Followup Item ILRT Integrated Leak Rate Test ISA Instrument Society of America IST In-Service Test LBLOCA Large Break Loss of Coolant Accident LOCA Loss of Coolant Accident LPI Low Pressure Injection LPIS Low Pressure Injection System MCC Motor Control Center l MSSV Main Steam Safety Valves l MWt Megawatt Thermal NOV Notice of Violation NRC Nuclear Regulatory Commission NRR Nuclear Reactor Re ulation NSS Nuclear Steam Supp y NSSS Nuclear Steam Supp y System L

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OP Operating Procedure OTSG Once Through Steam Generator PC Precursor Card PPO Primary Plant Operator PRC Plant Review Committee PT Performance Test RB Reactor Building

< RC Reactor Coolant i- RCP Reactor Coolant Pump RCS Reactor Coolant System RHR Residual Heat Removal SBLOCA Small Break Loss of Coolant Accident ~

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SB0 Station Blackout SER Safety Evaluation Report SGTR Steam Generator Tube Rupture SP Surveillance Procedure SP0 Secondary Plant Operator

! SR0 Senior Reactor Operator STA Shift Technical Advisor TBD Technical Bases Document TMI Three Mile Island TS Technical Specifications TSC Technical Support Center URI Unresolved Item US0 Unreviewed Safety Question UFSAR Updated Final Safety Analysis Report V&V Verification and Validation VAC Volts - Alternating Current

- VIO Violation j

' VSSV Vital System Status Verification l

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V. PREDECISIONAL ENFORCEMENT CONFERENCES Whenever the NRC has learned of the existence of a potential violation for which escalated enforcement action appears to be warranted, or recurring nonconformance on the part of a vendor, the NRC may provide an opportunity for a predecisional enforcement conference with the licensee, vendor, or other -

person before taking enforcement action. The purpose of the conference is to obtain information that will assist the NRC in determining the appropriate enforcement action. such as: (1) a common understanding of facts root causes and missed opportunities associated with the apparent violations, (2) a common understanding of corrective actions taken or planned, and (3) a common understanding of the significance of issues and the need for lasting comprehensive corrective action.

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If the NRC concludes that it has sufficient information to make an informed L enforcement decision, a conference will not normally be held unless the l licensee requests it. However, an opportunity for a conference will normally l be provided before issuing an order Jased on a violation of the rule on Deliberate Misconduct or a civil penalty to an unlicensed person. If a i conference is not held, the licensee will normally may be requested to

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provide a written resaonse to an inspection report, if issued. as to the licensee's views on t1e apparent violations and their root causes and a description of planned or implemented corrective actions. However, if the NRC has sufficient information to conclude that a civil penalty is not

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warranted, it may proceed to issue an enforcement action without first

obtaining the licensee's response to the inspection report.

! During the predecisional enforcement conference, the licensee. vendor, or

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other )ersons will be given an opportunity to provide information consistent with tie purpose of the conference, including an explanation to the NRC of the

! immediate corrective actions (if any) that were taken following identification of the potential violation or nonconformance and the long. term comprehensive

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actions that were taken or will be taken to prevent recurrence. Licensees, vendors or other persons will be told when a meeting is a predecisional l enforcement-conference.

L -A predecisional enforcement conference is a meeting between the NRC and the licensee. Conferences are normally held in the regional offices and are normally open to public observation. Conferences will not normally be open to the public if the enforcement action being contemplated:

l (1) Would be taken against an individual, or if the action, though not taken against an individual, turns on whether an individual has y committed wrongdoing:

(2) Involves significant personnel failures where the NRC has requested that the individual (s) involved be present at the L conference: (3) Is based on the findings of an NRC Office of Investigations report that has not been publicly disclosed: or Enclosure 3 i _ - _ _ _ _ _ _ --- __ _-_ - - --- -- - - - - - - - - - . - - _ - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

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(4) Involves safeguards information. Privacy Act information, or information which could be considered proprietary:

l In addition. conferences will not normally be open to the public if:

(5) The conference involves medical misadministration or overexposure and the conference cannot be conducted without l disclosing the exposed individual's name: or (6) The conference will be conducted by telephone or the conference will be conducted at a relatively small . licensee's facilit Notwithstanding meeting any of these criteria, a conference may still be open if the conference involves issues related to an ongoing adjudicatory proceeding with one or more interveners or where the evidentiary basis for the

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conference is a matter of public record, such as an adjudicatory decision by the Department of Labor. In addition notwithstanding the above normal criteria for opening or closing conferences, with the approval of the Executive Director for Operations, conferences may either be open or closed to the public after balancing the benefit of the public's observation against the potential impact on the agency's decision,, making process in a particular case.

l The NRC will notify the licensee that the conference will be open to public observation. Consistent with the agency's policy on open meetings. " Staff Meetings Open to Public." published September 20, 1994 (59 FR 48340), the NRC intends to announce open conferences normally at least 10 working days in advance of conferences through (1) notices posted in the Public Document Roo (2) a toll. free telephone recording at 800,952.,9674. (3) a toll,, free electronic bulletin board at 800,,952,9676, and on the World Wide Web at the NRC Office of Enforcement homepage (www.nrc. gov /0E). In addition, the NRC will also-issue a press release and notify appropriate State liaison officers that a predecisional enforcement conference has been scheduled and that it is open to public observatio The public attending open conferences may observe but may not participate in the conference. It is noted that the )urpose of conducting o)en conferences is not to maximize public attendance. )ut rather to provide t1e aublic with o)portunities to be informed of NRC activities consistent with tie NRC's a)ility to exercise its regulatory and safety res>onsibilities. Therefor members of the public will be allowed access to tie NRC regional offices to attend open enforcement conferences in accordance with the " Standard Operating Procedures For Providing Security Support For NRC Hearings and Meetings."

published November 1. 1991 (56 FR 56251). These 3rocedures 3rovide that

, visitors may be subject to personnel screening, tlat signs. Janners, posters.

l etc.. not larger than 18" be permitted, and that disruptive persons may be

! removed. The open conferences will be terminated if disruption interferes j with a successful conference. NRC's Predecisional Enforcement Conferences (whether open or closed) normally will be held at the NRC's regional offices Enclosure 3

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i or in NRC Headquarters Offices and not in the vicinity of the licensee's facilit For a case in which an NRC Office of Investigations (01) report finds that discrimination as defined under 10 CFR 50.7 (or similar provisions in Parts 30. 40. 60. 70, or 72) has occurred the 01 report may be made public, subject

' to~ withholding certain information (i.e. , after appropriate redaction) in which case the associated predecisional enforcement conference will normally be open to public observation. In a conference where a particular individual is being considered potentially responsible for the discrimination, the conference will remain closed. .In either case (i.e., whether the conference is open or closed), the employee or former employee.who was the subject of the alleged discrimination (hereafter referred to as " complainant") will normally be provided an opportunity to participate in the predecisional enforcement conference with t1e licensee / employer. This partici)ation will normally be in the form of a complainant statement and comment on tie licensee's presentation, followed in turn by an opportunity for the licensee to respond to the complainant's presentation. In cases where the complainant is unable to attend in person, arrangements will be made for the complainant's participation by telephone or an opportunity given for the complainant to submit a written response to the licensee's presentation. If the licensee chooses to forego an enforcement conference and, instead, res)onds to the NRC's findings in writing. the complainant will be submit written comments on the licensee's response.provided For cases involving t1e opportunity to potential discrimination by a contractor or vendor to the licensee, any associated predecisional enforcement conference with the contractor or vendor would be handled similarly. These arrangements for com)lainant participation in the predecisional enforcement conference are not to ]e conducted or viewed in any respect as an adjudicatory hearing. The purpose of the complainant *s participation is to provide information to the NRC to assist it in its enforcement deliberation A predecisional enforcement conference may not need to be held in cases where there is a full adjudicatory record before the Department of Labor. If a conference is held in such cases, generally the conference will focus on the licensee's corrective action. As with discrimination cases based on OI investigations, the complainant may be allowed to participat Members of the public attending open conferences will be reminded that (1) the ap]arent violations discussed at predecisional enforcement conferences are su) ject to further review and may be subject to change prior to any resulting enforcement action and (2) the statements of views or expressions of opinion made by NRC employees at predecisional enforcement conferences or the lack thereof, are not intended to represent final determinations or belief When needed to protect the public health and safety or common defense and security, escalated enforcement action. such as the issuance of an immediately effective order, will be taken before the conferenc In these cases, a conference may be held after the escalated enforcement action is take Enclosure 3 l

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