ML20137P236
| ML20137P236 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 10/11/1995 |
| From: | Ebneter S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | Lieberman J NRC OFFICE OF ENFORCEMENT (OE) |
| Shared Package | |
| ML20137P228 | List: |
| References | |
| FOIA-96-485 EA-95-180, NUDOCS 9704090191 | |
| Download: ML20137P236 (400) | |
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[\. 1 e NUCLEAR REGULATORY COMMIS810N REGeoN 11 101 MAR 8ETTA STREET, N.W., SUITE 2I00 ,
-h ATLANTA, GEORGIA 3DB5o198 '
..... October 11, 1995 .
l MEMORANDUM TO: . James Lieberman, Director
- Office of Enforcement FROM
- Stewart D. Ebneter, Regional Administrator p ,
SUBJECT:
EA 95-180, FLORIDA POWER AND LIGHT COMPANY, ST. LUCIE UNIT 1, , a PROPOSED SEVERITY LEVEL III PROBLEM, USE OF DISCRETION TO IMPOSE $50,000 CIVIL PENALTY l-Attached for your review and concurrence-is the proposed enforcement action for the subject case. An Enforcement Action Worksheet is provided as Attachment 1. - Attachment 2 consists of a draft letter to the licensee and a. Notice of Violation. Attachment 3 contains the reference material appropriate to this case. Three violations were identified for (1) the failure to meet Technical Specification requirements to maintain the Pressure Operated Relief Valves (PORVs) operable when at low pressure conditions; (2) the failure to adequately identify and perform post-maintenance testing of the PORVs; and (3) the failure to perform adequate inservice testing of the PORVs. We propose that the issue be ; classified as a Severity Level III problem consistent with Supplement I.C.2.a of the Enforcement Policy: A system designed to prevent or mitigate a serious safety event not being able to perforin its intended function under certain conditions. Application of the civil penalty assessment process would have resulted in a fully mitigated civil penalty but due to the poor licensee performance in this case, discretion was applied to impose the base civil penalty. This case is not exempt from the Office of Enforcement's timeliness requirements. Attachments: 1. Enforcement Action Worksheet
- 2. Draft Letter /NOV to Licensee ,
- 3. Reference Package cc w/atts: J. Goldberg, OGC R. Zimmerman, NRR CONTACT: B. Uryc, RII 404-331-5505 9704090191 970407 PDR FOIA 96-405 PDR
- < m . ,_
r l l ENFORCEMENT ACTION WORKSHEET , Revision 1 Post-Conference Caucus / Final EA 95-180-Region II - Non- Delegated Case
, Licensee:' Florida Power and Light Company St. Lucie Nuclear Plant Docket No. 50-335-License No. DPR-67 p Dated Inspection Ended: ' August 30, 1995 s
- 1. Brief Summiary of Inspection Findings:
A detailed discussion of the inspection findings is provided in Inspection Report Nos. 50-335/95-16 and 50-389/95-16. A Severity Level III problem is proposed for: (1) the failure to meet Technical Specification requirements to maintain Pressure Operated Relief Valves (PORVs) V-1404 and V-1402 operable when at low pressure conditions; (2) the failure to adequately identify and perform post-maintenance testing of PORVs V-1404 and V-1402; and (3) the failure to perform adequate inservice testing of the PORVs.
- All three issues were combined into a Severity Level III prublem because the combined failures to comply with regulatory requirements resulted in a common mode failure of the PORVs and the failure to detect the inoperable PORVs through re' quired testing between November 1994 and August 1995.
- 2. Analysis of Root Cause:
The licensee's root cause analysis as described at the predecisional enforcement conference was limited to the immediate deficiencies. However, the NRC inspection of this case and'the licensee's-corrective action indicates that the licensee recognizes that there are other root causes in management and control of maintenance and testing and commits to corrective actions that include comprehensive reviews of procedures. t
- 3. Basis for Severity level (Safety significance):
The safety significance of.the proposed action is consistent with a Severity Level III, Enforcement Policy Supplement I.C.2.a: A system designed to prevent or mitigate a serious safety event not being able to perform its intended function under certain conditions. PROPOSED ewCRCninNT ACTION - NOT FOR PURUC DISCLOSURE WffMOUT THE APPROVAL OF THE DIRECTOR. OE Attachment 1
<r
y__ _. __ .. . _ - _ - .. _. _ . .- ___ _ _- n ', ,.9-w , k . )' Enforcement' Action 2. Worksheet- , EA 95-180-I
- 4. .Insntify Previous Escalated Action within 2 Years or 2 Inspections? !
% \
I 5. -Identification Credit? N/A , l Note that the event was considered self-disclosing as a result of..the l 1 failure to achieve required results in inservice tes. ting. i 2
- 6. Corrective Action Credit? Yes
( 1
'Immediate corrective actions included restoring the valves to an operable status, revising maintenance and test procedures, and, I conducting a comprehensive review of the valve failure. Planned long-f term corrective actions included, in part, (1) a phased review of other maintenance and test procedures to ensure quality control attributes are
- identified and verified, and that post-maintenance and inservice testing i
adequately demonstrates operability; (2) consolidating test groups under ! ' a single manager; and (3) training on accountability and administration ! i- in regard to control of contractors. Although weaknesses were i identified in root cause analysis for this event, the NRC determined that credit was warranted for the factor of Corrective Action. ) 7. Candidate for Discretion? Yes ! Section VII.A of the Enforcement Policy allows for the use of discretion i to propose a civil penalty where application of the factors would l
- otherwise result in a zero civil penalty to reflect the significance of i i
the violation and convey the appropriate regulatory message. This case 1 8 involves a situation where the licensee's performance was particularly i poor. 'Specifically, multiple opportunities existed during routine l L activities conducted by diverse groups to recognize the inoperability of . the PORVs. The failure of these diver:e groups to ensure system ! operability and the resulting loss of a safety function required by I Technical Specifications is a significant safety and regulatory concern. 1 Rigorous maintenance controls, adequate operator attention to diverse control board indications during testing,' adequate management reviews of i testing criteria and results, or adequate post trip data analysis during L l the July 1995 unit trip sheuld have detected that the PORVs were inoperable. Therefore, we propose that a base civil penalty be imposed in this case to ensure the appropriate regulatory message that programs
- must provide defense in depth to preclude common mode failures.
- 8. Is a Predecisional Enforcement Conference Necessary? Conducted 9/25/95 If yes, should OE or OGC attend? Yes p
Should conference be closed? Closed through the random selection j
- . process.
I PROPOSED EWORCBMNT ACTION NOT FOR PuRUC DISCLOSURE WITit0UT TIE APPROVAL OF TIE DIMCTOR. OE i i E
i A m- , Enforcement Action 31 Worksheet ' EA 95-180 l 1
- 9. Non-Routine Issues / Additional Information: l l
None j l
- 10. This Action is consistent with the Following Action (or Enforcement l Guidance) previously issued:
4 Supplement I.C.2.a of the Enforcement Policy f '
- 11. Regulatory Message:
The NRC is particularly concerned that procedures and controls in diverse parts of the maintenance and testing process failed and led to a common mode ~ failure of tile PORVs. In addition, opportunities to . recognize the inoperability of the valves during a unit trip and during inservice tests were missed. The tallure to maintain programs to provide defense in depth and preclude common mode failures is a significant rcgulatory concern.
- 12. Recommended Enforcement Action:
9 The recommended enforcement action is a Severity Level III problem. The post-conference caucus concluded that the licensee had no escalated enforcement in the past two years and'the licensee should be given credit for the factor of corrective actions. The basis for this credit is discussed in Section 6 above. However, discretion was exercised to propose a base civil penalty because of poor licensee performance in this situation (Section 7 above.) ;
- 13. This case meets the criteria for a Delegated Case. No
- 14. Should this action be sent to OE for full review? Yes Rsquires approval by the Deputy Executive Director for Nuclear Reactor '
Regulation, Regional Operations and Research due to the exercise of discretion to impose a civil penalty.
- 15. Regional Counsel Review No Legal Objection Dated: October 11, 1995
- 16. Exempt from Timeliness: No Basis for Exemption: Not Applicable Enforcement Coordinator: Linda J. Watson 404-331-5534 Date: October 11, 1995 PROPOSED ENFORCEMENT ACTION - Not Fca PUBUC DISCLOSURE MTHoVT TM APPROVAL OF TM DIRECTOR. oE k - -
e 1 EA 95-180 Fl yida Power and Light Company ATTH: Mr. J. H. Goldberg President - Nuclear Division P. O. Box 14000 Juno Beach, FL 33408-0420 1 1
SUBJECT:
NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY - l
$50,000 ,
(NRC Inspection Report No. 50-335/95-16 and 50-389/95-16) j
Dear Mr. Goldberg:
This refers to the inspection conducted on August 9-30, 1995, at St. Lucie 1 Nuclear Plant. The inspection included a review of the circumstances associated with the incorrect installation of a key component in both of the Unit 1 Power Operated Relief Valves (PORVs) resulting in inoperability of both PORVs. The results of our inspection were sent to you by letter dated September 8, 1995. A closed predecisional enforcement conference was ( conducted in the Region II office on September 25, 1995, to discuss tne apparent violations, the root causes, and your corrective actions to preclude recurrence. A list of conference attendees, NRC slides, and a copy of your presentation summary are enclosed. Based on the information developed during the inspection and the information you provided during the conference, the NRC has determined that violations of NRC requirements occurred. These violations are cited in the enclosed Notice of Violation and Proposed Imposition of Civil Penalty (Notice) and the circumstances surrounding them are described in detail in the subject inspection report. Violation A, described in the enclosed Notice, involved the failure to meet Technical Specification requirements to maintain PORVs V-1404 and V-1402 operable when at low pressure conditions. The valves were inoperable because the main disc guide had been installed upside down during routine maintenance. Although the direct root cause of Violation A was the failure of contractor technicians to specifically follow the approved maintenance procedure, other weaknesses contributed to the errors. The maintenance activities were performed on both valves by the same technicians; however, additional controls were not in place to ensure operability and protect against a ccmmon mode failure such as verification of orientation of the main disc guide by quality control or independent verification by a second party. Violation B involved the failure to adequately identify and perform post-maintenance testing of PORVs V-1404 and V-1402 in order to demonstrate that the valves would perform satisfactorily in service after valve maintenance was performed. Although testing was performed to confirm that seat leakage requirements were met, you failed to identify and perform testing to ensure that the valves would funct. ion as required under pressure. Testing to ensure satisfactory performance of valves in service is a requirement of Appendix B, PMoPOSED ENFOMCEMENT ACTICH - NOT FOR PVSUC DISCLOSUM m Attachment 2
a m , t FP&L 2 Criterion XI, Test Control. The root causes of this violation could involve several functional areas, however, the root cause you discussed in the predecisional enforcement conference was limited to the immediate procedural deficiency. Violation C involved the failure to perform adequate inservice testing of the PORVs. The inservice testing performed relied solely on the use of acoustic monitoring of valve discharge to indicate valve position. .This method was not sufficient to discern the difference between bypass flow through the PORY pilot valves and actual changes in main valve position. At low pressure the inservice test was performed with the block valves open providing multiple alternative indications of PORV position. The violation was caused by the reliance on one insufficient parameter rather than using diverse indications to determine valve position. The NRC relies on implementation of strong maintenance and testing programs to ensure operability of key components. The NRC is particularly concerned that your procedures and controls in diverse parts of the maintenance and testing process failed and led to a common mode failure of the PORVs. In addition, opportunities to recognize the inoperability of the valves during a unit trip and during inservice tests were missed. The safety consequences of these multiple errors were that the availability of both PORVs for secondary heat removal in a post accident condition and for low temperature overpressure protection was lost. The failure to maintain programs that provide defense in depth to preclude common mode failur's is a significant safety and regulatory concern. Therefore, these violations are classified in the aggregate in accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy), (60 FR 34381; June 30,1995/NUREG-1600) as a Severity Level III problem. In accordance with the Enforcement Policy, a base civil penalty in the amount of $50,000 is considered for a Severity Level III problem. Because your facility has not been the subject of escalated enforcement actions within the last two years, the NRC considered whether credit was warranted for Corrective Actfon in accordance with the civil penalty assessment provision in Section VI.B.2 of the Enforcement Policy. Your immediate corrective actions included 1 restoring the valves to an operable status, revising maintenance and test procedures, and conducting a comprehensive review of the facts and circumstances which led to the valve failure. Your planned long-term corrective actions included, in part, (1) a phased review of other maintenance and test procedures to ensure quality control attributes are identified and verified and that post-maintenance and inservice testing adequately demonstrate operability; (2) consolidating test groups under a single manager; and (3) training on accountability and administration with regard to the control of contractors. Although weaknesses were identified in the root cause 1 analysis for this event, the NRC determined that credit was warranted for the i factor of Corrective Action. . In accordance with Section VII.A of the Enforcement Policy, the NRC may exercise discretion by proposing a civil penalty where application of the factors would otherwise result in a zero civil penalty to ensure that the proposed civil penalty reflects the significance of the circumstances and I PROPOSED ENFORCEMENT ACTION - NOT FOR PUeUC DWClosURE ! WITHOUT THE APPROVAL OF THE DmECTOR. OE
^ "
4 FP&L 3 i 1 j conveys-the appropriste regulatory message. The NRC has weighed the , 4 circumstances of this case and finds that it involves a situation where your
- - performance was particularly poor.- Specifically, multiple opportunities existed during routine activities conducted by diverse groups to recognize the inoperability of the PORVs. The failure of these diverse' methods to ensure c system operability and the resulting loss of a safety function required by <
j your Technical Specifications is a significant safety and regulatory concern. l Rigorous maintenance controls, adequate operator attention to diverse centrol i- board indications during testing, adequate management reviews of testing criteria and results, or adequate post trip data analysis during the July 1995 ' , unit trip should have detected that the PORVs were inoperable. Therefore, to < emphasize the importance of maintaining adequate and diverse methods to ensure t
- system operability,'I have been authorized, after consultation with the '
. Director, Office of Enforcement and the Deputy Executive Director for Nuclear Reactor Regulation, Regional Operations and Research,- to issue the enclosed 2 Notice of Violation and Proposed Imposition of Civil Penalty (Notice) in the ' . base amount of $50,000 for the Severity Level III problem. You are required to respond to this letter and should follow the instructions 2 specified in the enclosed Notice when preparing you response. In your j response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future - inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements. . In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of
- this letter, its enclosure, and your response will be placed in the NRC Public Document Room (PDR). To the extent possible, your response should not include 3
any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without redaction. i ! The responses directed by this letter arid the enclosed Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No. 96.511. Sincerely, 4 Stewart D. Ebneter
- Regional Administrator i
l Docket No. 50-335
- License No. DPR-67
Enclosures:
- 1. Notice of Violation and Proposed Imposition of Civil Penalty
-2. List of Attendees
- 3. NRC Slides
- 4. Licensee Presentatio'n Handout I
cc w/encis: (See next page) - PROPOSE) BEORM ACTION - NOT FOR Punic DisoLosuRE WITHOUT TDE APPROVAL OF TIE DMECTOR. OE i
- , , - ..n - ., , - - - , . - - .
. =
FP&L 4 cc w/encis: D. A. Sager, Vice President Bill Passetti St. Lucie Nuclear Plant Office of Radiation Control P. O. Box 128 Department of Health and Ft. Pierce, FL 34954-0128 Rehabilitative Services 1317 Winewood Boulevard , H. N. Paduano, Manager Tallahassee, FL 32399-0700 Licensing and Special Programs .
- Florida Power and Light Company Jack Shreve
- P. O. Box 14000 Public Counsel i Juno Beach, FL 33408-0420 Office of the Public Counsel
- c/o The Florida Legislature l J. Scarola, Plant General Manager 111 West Madison Avenue, Room 812 J St. Lucie Nuclear Plant Tallahassee, FL 32399-1400 P. O. Box 128 Ft. Pierce, FL 34954-0128 Joe Myers, Director Division of Emergency Preparedness
! Robert E. Dawson Department of Comunity Affairs
. Plant Licensing Manager 2740 Centerview Drive St. Lucie Nuclear Plant Tallahassee, FL 32399-2100 P. O. Box 128 Ft. Pierce, FL 34954-0218 Thomas R. L. Kindred County Administrator J. R. Newman, Esq. St. Lucie County Morgan, Lewis & Bockius 2300 Virginia Avenue 1800 M Street, NW Ft. Pierce, FL 34982 Washington, D. C. 20036 i Charles B. Brinkman John T. Butler, Esq. Washington Nuclear Operations ,
Steel, Hector and Davis ABB Combustion Engineering, Inc. 4000 Southeast Financial Center 12300 Twinbrook Parkway, Suite 3300 Miami, FL 33131-2398 Rockville, MD 70852 j. 1 t { 2 4 4 4 ! PROPOSED Br0RCEMBIT ACTION - NOT FOR PURUC DISCLOSUIE WITHOUT TM APPROVAL OF TM DMECT0fL OE
o+ FP&L 5 Distribution w/ enc 1s: PUBLIC JTaylor,- EDO JMilhoan, DEDR SEbneter, RII LChandler, OGC JGoldberg, OGC i EJulian, SECY .
' BKeeling,.CA Enforcement Coordinators RI, RIII, RIV JLieberman, OE JGray, OE OE:EA File (B. Summers, OE) (2)
MSatorius, OE EHayden, OPA 4 DDandois, OC LTemper, OC GCaputo, 01 EJordon, AE00 '
- DWilliams, OIG i CEvans, RII BUyrc, RII KClark, RII RTrojanowski, RII CCasto, RII Klandis, RII (IFS Update)
JNorris, NRR GHallstrom, RII IMS:RII . NUDOCS NRC Resident Inspector U.S. Nuclear Regulatory Comm. 7585 South Highway A1A Jensen Beach, FL 34957-2010
. 1 l
l l PROPOSED Br0RCEMENT ACTION - NOT FOR PURUC DISCLOSURE j wrrMOur THE APPROVAL OF THE DEWCTOR. OE j
= m NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY Florida Power and Light Company Docket No. 50-335 St Lucie Unit 1 License No. DPR-67 EA 95-180 f
During NRC inspections' conducted on August 9-30, 1995, violations of NRC ' requirements were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," (60 FR 34381; , June 30,1995/NUREG-1600), the Nuclear Regulatory Commission proposes to impose a civil penalty pursuant to Section 234 of the Atomic Energy Act of ' 1954, as amended (Act), 42 U.S.C. 2282, and 10 CFR 2.205. The particular problem and associated civil penalty are set forth below: A. Technical Specification 3.4.13' requires, in part, that two Power r Operated Relief Valves (PORVs) be operable in Mode 4 when the temperature of any RCS cold leg is less than or equal to 304*F, in Mode ' 5 and Mode 6 when the head is on the reacter vessel; and the RCS is not 1 vented through a greater than 1.75 square inch vent. Technical Specification 3.4.13, Action Statement (c), requires that, with both PORVs inoperable, at least one PORV be returned to an operable status or that the RCS be completely depressurized and vented through a minimum 1.75 square inch vent within 24 hours. Contrary to the above, from November 22 through 27, 1994, and from February 27 through March 6, 1995, while St. Lucie Unit I was in one of , the conditions specified in Technical Specification 3.4.13 requiring operable PORVs, PORVs V-1404 and V-1402 were inoperable because the main
- disc guide had been installed upside down and the provisions of Technical Specification 3.4.13, Action Statement (c) were not met.
(01013) ; B. 10 CFR 50, Appendix B, Criterion XI requires, in part, that a test program be established to ensure that all testing required to demonstrate that components will perform satisfactorily in service is identified and performed in accordance with written test procedures , which contain the requirements and acceptance limits contained in applicable design documents and that the test program shall include proof tests prior to installation. FPL Topical Quality Assurance Report TQR 11.0, revision 4, Test Control, states, in part, that a test program j shall be established to assure that testing required to demonstrate that components will perform satisfactorily in service is performed and that the program shall include proof tests prior to installation. I
> Contrary to the above, after maintenance performed on November 4, 1995, the licensee failed to adequately identify and perform post-maintenance testing of Power Operated Relief Valves V-1404 and V-1402 to demonstrate ,
that the valves.would perform satisfactorily in service after valve maintenance was performed. Specifically, the post-maintenance test I performed did not include a verification that the valve would change state under' pressure prior to installation. (01012) PROPOSED ENFORCEMBff ACTION NOT FOR PUeuC DISCLOSURE wirwoUT THE APPROVAL OF THE DETECTOR. OE Enciosure 1 l t
.O ' b i l Notice of Violation and Proposed 2 i
> Imposition of Civil Penalty l C. 10 CFR 50.55a(f)(4)(ii) requires, in part, that inservice te'sts to l verify operational readiness of valves, whose function is required for ! safety, conducted during successive 120-month intervals, must comply i with requirements of the latest edition and addenda of the ASME Code. . Florida Power and Light Second Ten-year Inservice Inspection Interval l Inservice Testing Program For Pumps and Valves, Document Number JNS-PSI J 203, Revision 5, states, in part, that, between February 11, 1988 and February 10, 1998, the St. Lucie Unit 1 ASME Inservice. Inspection (IST) > 3 Program will meet the requirements of the ASME Boiler and Pressure ' 4 Vessel Code.(the Code), Section XI, 1983 Edition. ' Section XI of the 1983 ASME Boiler And Pressure Vessel Code, article IWV-3000, Test Requirements, Section IWV-3200, Valve Replacement, ! Repair, and Maintenance, requires, in part, that when a valve or its i i control system has been replaced or repaired or has undergone l maintenance that could affect its performance, and prior to the time it !
- is returned to service, it shall be tested to demonstrate that the l performance parameters, which could be affected by the replacement, j repair, or maintenance are within acceptable limits.
l Contrary to the above, on November 25, 1994 and February 27, 1995, after maintenance that could have affected the performance of Power Operated j
- Relief Valves V-1404 and V-1402, the licensee failed to perform inservice testing that would demonstrate that the performance parameters of valves V1404 and V-1402 were within acceptable limits. Specifically, operational surveillance testing, performed under Administrative Procedure 1-0010125A, revision 39, Data Sheet 24, did not include an 3: adequate test to detect that the main disc guides in valves V-1404 and
- V-1402 were misoriented causing the valves to be inoperable. (01033)
These violations represent a Severity Level III problem (Supplement I). This violation is applicable to Unit 1 only, a Civil Penalty - $50,000. Pursuant to the provisions of 10 CFR 2.201, Florida Power and Light Company is
, hereby required to submit a written statement or explanation to the Director, s
' Office of Enforcement, U.S. Nuclear Regulatory Commission, within 30 days of the date of this Notice of Violation and Proposed Imposition of Civil Penalty (Notice). This reply should be clearly marked as a " Reply to a Notice of )
Violation" and should include for each alleged violation: (1) admission or denial of the alleged violation, (2) the reasons for the violation if l
. admitted, and if denied, the reasons why, (3) the corrective steps that have {
been taken and the results achieved, (4) the corrective steps that will be j taken to avoid further violations, and (5) the date when full compliance will be achieved. c I PROP 0eED ENFORCEMENT ACTION NOT FOR PUELIC DECL0eURE WITHOUT Tif APPROVAL OF THE DMECTOR. OE
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. ..- .- - - - - -.- - - - .. - - -. .... . - . . . ~ . _ . . _ _ - - -
m . l , 4 i i' Notice of Violation and Proposed 3 i Imposition of Civil Penalty ! 1 i If an adequate reply is not received within the time specified in this Notice, l an order or a Demand for Information may be issued as why the license should , not be modified, suspended, or revoked or why such other action as may be proper should not be taken. Consideration may be given to extending the ; response time for good cause shown. Under the authority of rection 182 of the Act, 42 U.S.C. 2232, this response shall be submitted under cath or affirmation. : i Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalty by letter addressed to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, with a check, draft, money order, or electronic transfer payable.to the Treasurer i of the-United States in the amount of the civil penalty proposed above, or the : cumulative amount of the civil penalties if more than one civil penalty is proposed, or may protest imposition of the civil penalty in whole or in part,
;by a written answer addressed to the Director, Office of Enforcement, U.S.
Nuclear Regulatory Commission. Should the Licensee fail to answer within the , time specified, an order imposing the civil penalty will be issued. Should j the Licensee elect to file an answer in accordance with 10 CFR 2.205 - protesting the civil penalty, in whole or in part, such answer should be clearly marked as an " Answer to a Notice of Violation" and may: (1) deny the i violation (s) listed in this Notice, in whole or in part, (2) demonstrate extenuating circumstances, (3) show error in this Notice, or (4) show other reasons why the penalty should not be imposed. In addition to protesting the civil penalty in whole or in part, such answer may request remission or mitigation of the penalty. 1 In requesting mitigation of the proposed penalty, the factors addressed in i Section VI.B.2 of the Enforcement Policy should be addressed. Any written ; answer in accordance with 10 CFR 2.205 should be set forth separately from the 3 statement or explanation in reply pursuant to 10 CFR 2.201, but may incorporate parts of the 10 CFR 2.201 reply by specific reference (e.g., - citing page and paragraph numbers) to avoid repetition. The attention of the Licensee is directed to the other provisions of 10 CFR 2.205, regarding the procedure for imposing.a civil penalty. t Upon failure to pay any civil penalty due which subsequently has been determined in accordance with the applicable provisions of 10 CFR 2.205, this , matter may be referred to the Attorney General, and the penalty, unless compromised, remitted, or mitigated, may be collected by civil action pursuant to Section 234c of the Act, 42 U.S.C. 2282c. The response noted above (Reply to Notice of Violation, letter with payment of i civil penalty, and Answer to a Notice of. Violation) should be addressed to: Mr. James Lieberman,. Director, Office of Enforcement, U.S. Nuclear Regulatory i Commission, One White Flint North,11555 Rockville Pike, Rockville, MD 20852- : 2738, with a copy to the Regional Administrator, U.S. Nuclear Regulatory ! Commission, Region II and a copy to the NRC Resident Inspector at the St. Lucie facility. N ENFORCEWENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DutECTOR. OE
a m O i
- g. I Notice of Violation and Proposed 4 :
. Imposition of Civil Penalty Because your response will be placed in the NRC Public Document Room (PDR), to
-the extent possible, it should not include any personal privacy, proprietary, or safeguards information so'that it can be placed in the PDR without redaction. However, if you find it necessary to include such information, you i should clearly indicate the specific information that you desire not to be !
placed in the POR, and provide the legal basis to support your request for withholding the information from the public. Dated at Atlanta, Georgia this day of October 1995 e 1 I i a j i l 1 l PROPOSED ENFORCEMENT AC ' ION NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR OE l
J . .m . . , c!
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LIST OF ATTENDEES Licensee
.J. Goldberg, President, Nuclear division .
D. Sager, Vice President, St. Lucie Site l J. Geiger,.Vice Presidenti Florida Power and Light company (FPL) l W. Bohlke, vice President, Engineering , L. Bradow, Nuclear Assurance Manager L. Rogers, Systems and Component Engineering Manager . L J. Marchese,-Maintenance Manager l J. West Operations Manager !' R. Golden, Nuclear Information Coordinator , FPL-Nuclear Regulatory Commission S. Ebneter, Regional Administrator, Region II , JE. Merschoff, Director, Division of Reactor Projects (DRP) -
; A. Gibson, Director, Division of Reactor Safety (DRS) i, B. Uryc, Director, Enforcement and Investigation Coordination Staff ,
K. Landis, Branch Chief, Reactor Projects Branch 3, DRP D. Prevatte, Senior Resident Inspector, St. Lucie Nuclear Plant i C. Evans,' Regional Attorney ; L. Watson, Enforcement Specialist B. Schin, Project Engineer, DRP . E. Lea, Project Engineer, DRP G. Hopper, Reactor Engineer, DRS ;
- M. Satorius, Enforcement Coordinator, Office of Enforcement (by telephone) !
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SUMMARY
OF F5 CTS OF CASE (ANNUAL REPORT FORMAT'FOR EATS ENTRY)'tMAXIMUM OF S00 CHARACTERS) 'Y UNIT 1 PORVs WERE INOPERABLE DUE TO PERSONNEL ERROR DURING MAINTENANCE AND INADEQUATE POST-MAINTENANCE AND ' SURVEILLANCE TESTING FAILED TO DETECT INOPERABLE CONDITION.
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ESCALATED ENFORCEMENT l PANEL QUESTIONNAIRE 1 INFDRMATION REQUIREQ TO BE AVAILABLE FOR ENFORCEMENT PANEL 3 l PREPARED BY: R. Prevatte NOTE: The Section Chief is responsible for . preparation of this questionnaire , and its distribution to attendees prior to an Enforcement Panel. (This ; information will be used by EICS to >repare the enforcement letter and Notice, i as well as the transmittal memo to tie Office of Enforcement explaining and ' justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit (s): 1 Docket Nos: 50-335 License Nos: DPR-67 l
Inspection Dates: July 30 - September 16. 1995 l Lead Inspector: Richard L. Prevatte
- 2. Check appropriate boxes:
)
[X) A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is enclosed. [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated.
]
j [] Copies of applicable Technical Specifications or license 1 conditions cited in the Notice are enclosed. I
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best i fits the violation (s) (e.g., Supplement I.C.2) )
1.C.7 i
- 4. What is the apparent root cause of the violation or problem?
)
Failure to follow crocedures (multiole examples - 8)
- 5. State the message that should be given to the licensee (and industry) !
through this enforcement action. I Procedures must be used and followed. If errors exist in the orocedures that prevent followino them. the errors must be corrected. 1
4
- 6. Factual information related to the following civil penalty escalation or
[ . mitigation factors-(see attached matrix and ; 10 CFR Part 2, Appendix C, Section VI.B.2.): : i ,' a. IDENTIFICATION: (Who identified the violation? What were the i facts and circumstances related to the discovery of the violation? Was it self-disclosing? Was it identified,as a result of a [ generic notification?) '
'4 nr = les 'dentified by NRC. 2 ex= -les by licensee. and 2 were !
. se' f-10entifyina,
]'
- b. CORRECTIVE ACTION: Although we expect to learn more information ;
regarding corrective action at the enforcement conference, i
' describe preliminary information obtained during the inspection
- and exit interview. !
i Jane procedure chanaes madn. personnel disciolined. and licensee strivina to improve standards and performance. 5 What were the immediate corrective actions taken upon discovery of 1 the violation, the development and implementation of long-ters , corrective action and the timeliness of corrective-actions? Prompt action taken each event. i What was the degree of licensee initiative to address the j violation and the adequacy of root cause analysis? I- This is a lona term action problem.
, c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer. --
- List past violations that may be related to the current violation l (include specific requirement cited and the date issued): j l
NCV 95-07. Loss SDC - incorrect valve manipulation by operator. j VIO 94-22-02. Lockeeoina errors. 4 Identify the applicable SALP category, the rating for this i , category and the overall rating for the last two SALP periods, as well as any trend indicated: ! Doerations 1 Recent events indicate neaative trend.
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities for the licensee to discover the violation sooner such as through normal surveillances, audits, QA activities, specific NRC or industry notification, or reports by employees? j g
a d
. . + . _ _ _ . _ .
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the -
violation identified during this inspection? If there were, ; identify the number of examples and briefly describe each one. ! 8 era-las. see attached violations
- f. DURATION: How long did the violation exist? .
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EgCALAficN Als MITIGAtl0N FAC70ts (57 Fa 5791, February 13, 1992) IgENTIFICATION CMEECTIVE LIGum psica leILTIPLE gmATIM ACTIM Pgarnommers WFWTWITT To nrn amourse IgENTIFT
+/ SOE +/ 505 +/ 1001 + 1005 + 100E + 1005 Licensee Timeliness of Current Licensee eheutd multiple used for i identified (M) corrective violetten.is on have identified examples of significant i
. [To be applied action (M) feelsted violation violetten reputatory even if IDid NRC have fatture that is seener as a identified message to ticensee could to intervene to inconsistent result of prior daring licensee. (E) ! have accesptlah with licensee's opportamities inspection identified the satisfactory good such as audits (enty for SL I, vlotation short term or perfonmence (M) (E) Il er !!I sooner) remediet action vlotettens) (E) (E)) NRC identified Promptly Violetten is opportunities OfMER CIWS10ERAffMS (E) developed reflective of .evellable to
- schedute for licensee's poor discover 1. Leget aspects and potentist long tens or declining vlotetton such litigation risks i corrective performance (E) es through _-.
action (M) prior 2. sogligence, eerstesa dis-notification regard, wittfulness and (E) annagement invotvenant self- Degree of Prior Ease of certler 3. Eoenomic, persenet or disclosing Licensee performance and discovery (E) corporate pain (M 25% ff initletive (M) effectiveness there was (To develop of previous 4. Any other regulatory frame. , initiative to corrective corrective work facters that need to bec l identify root actims and actlen for considered pending.sctlen ; cause) root cause) simiter with regard te (foonsing, vlotettens comotesian meeting, or press I Licensee Adequecy of the SALP = Perled of time I identified as root cause Considers between 5. lest la the intended esosage a result of onstysis for SALP 1 - (M) violation and for the tioensee and the poneric the vlotation SALP 2 * (0) notification Irdsstry? notification (M) SALP 3 - (E) received by (M) Licensee (E) ......... 30TEs.......... Comprehensive Prior Similarity corrective enforcement between the action to history vlotetten and prevent including notifIcetlen occurrence of escalated and (E) e similar non-escateted vlotation (M) enforcement immediate Level of sorrective annocement action not review the taken to notification ' restore safety received (E)
- and compliance (E)
SAFETY SIGNIFICANCE: In determining the safety significance of a vietetten in conjmetion with the enforcement process, the evenustian should censider the technical safety significance of the vietetten es well as the regulatory significence. Consideration should be given to the metter as a d ele in light of the circumstances surrounding the vlotetten. There may be cases in which the technicet safety significance of the matter is low while the process control failure (s) may be significent, and, therefore, the severity level determination should be booed more on the process centrol felture(s) then . on the technicet safety leeue. The fottowing factors should also be considered: 1) Did the vietetten actuelty or potentistly lopect pelle health and safety?. 2) Wat was the root cause of the vlotetlan?
- 3) is the vlotetten en isoleted incident or is it indicative of a prograusstic breakdown? 4) Wes mennesment euere of or involved in the vlotetten? 5) Did the violation Irwolve willfulness?
t r _,- . . _ _ - _ _ _ _ - - ~ - ._ _ _ _ _ _ - _ - _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _
.. l 1
l i l J l Proonsed Violation A ) ! Technical Specification 6.8.1.a required that written procedures be - l d established, implemented, and maintained covering the activities
- recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February 1978. Appendix A, paragraph 1.d includes administrative procedures for procedural adherence. Procedure QI 5-PR/PSL-1, Rev 62, " Preparation, 1
+ Revision, Review / Approval of Procedures," Section 5.13.2, stated that all procedures shall be strictly adhered to. .
- Contrary to the above, the following examples of procedural noncompliance were identified
- 1. OP l-0030127, Rev 68, " Reactor Plant Cooldown - Hot Standby to Cold Shutdown," required, in part, that operators block Main Steam Isolation System (MSIS) actuation when block permissive ,
annunciations were. received. ONOP l-0030131, Rev 60, " Plant ! Annunciator Summary," required that, upon valid receipt of annunciators Q-18 and Q-20, operators immediately block MSIS
- channels A and B, respectively.
4 Contrary to the above, on August 2, 1995, during a cooldown of St. -
- Lucie Unit 1, operators failed to establish the required MSIS blocks, resulting in A and B channel MSIS actuations.
J
- 2. OP l-0120020, Rev 72, " Filling and Venting the RCS," precaution 1 4.2, required that Reactor Coolant System (RCS) venting, described 1
in the procedure, not be attempted if RCS temperature was above 200*F. j Contrary to the above,- on August 2,1995, Reactor Coolant Pump ; i (RCP) seal venting, perfomed in an attempt to correct seal ! i package leakage in the IA2 RCP in accordance with Appendix t. of l'
- the subject procedure, was performed while RCS temperature was
- approximately 370*F. As a result, design temperatures of RCP seal
[ components were approached or exceeded. i 3I OP l-6120020, Rev 72, " Filling and Venting the RCS," Appendix E.
" Restaging Reactor Coolant Pump Seals," required the use of RCP seal injection while restaging was attempted.
contrary to the above, on August 2,1995, restaging of the IA2 RCP
, seal package was attempted without seal injection aligned to the seal package. As a result, design temperatures of RCP seal components were approached or exceeded.
4.h OP l-0010123, Rev 99, " Administrative Controls of Valves, Locks, and Switches," step 8.1.6, required, in part, that all valve position deviations be documented in the Valve Switch Deviation , Log. j Contrary to the above, on or about August 1, 1995, HCV-25-1 through 7 were repositioned and left in the closed position
- - - . . - -- . - - . - = ._.-- - ---
f d without the; required entries being made in the Valve Switch - Deviation Log. The valves' positions exacerbated a loss of RCS inventory. - 5.Y OP 0010129, Rev 24, " Equipment Out-of-Service," step 3.2, required ' that all equipment required by Technical Specifications be logged
, in the Equipment Out-of-Service Log when determined to be ; inoperable.
. Contrary to the above, inspections performed on September 1 and 2, l i 1995, identified inoperable equipment, required by Technical Specifications, which had not been placed in the Equipment Out-of-
; Service Log. Specifically, Unit 1 Containment Purge Valve FCV ,
- 4 and the IB Emergency Diesel Generator Fuel 011 Transfer Pump '
were both inoperable without being entered into the Equipment Out-of-Service Log. l 6. OP 1-0410022, Rev 22, " Shutdown Cooling," step 8.3.7, required that V3652, the B Shutdown Cooling (SDC) hot leg suction isolation
- valve, be locked open while placing the B SDC loop in service.
Contrary to the above, on August 29,-a control room operator failed to place V3652 in a locked open condition while placing the B SDC loop in service. As a result, the IB Low Pressure Safety Injection Pump was. operated with its suction line isolated. I
- 7. QI 16-PR/PSL-2, Rev 1, "St. Lucie Action Report (STAR) Program,"
required that STARS be initiated for Quality Assurance audit findings and independent technical review recommendations. . Contrary to the above, a STAR was not generated when a Quality Assurance review of an inadvertent Unit I containment spraydown, documented in interoffice correspondence _JQQ-95-143, identified . the practice of pre-lubricating FCV-07-1A, Containment Spray header A flow control valve, when performing valve stroke time testing.
- 8. ADM-08.02,'Rev 7, " Conduct of Maintenance," Appendix 5, step 5, required that procedures be present during work and that individual steps be initialed once performed.
Contrary to the above, inspection of work in progress revealed that individual steps were not initialed upon completion for work
. conducted in accordance with Plant Change / Modification 11-195.
This is a Severity Level III violation (Supplement I). i 1 I
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A EXCERPTS FROM IR 95-15 3)- RCP Seal Failure 1 l Background St. Lucie employed Byron-Jackson RCPs and seal packages. The packages consisted of 3 primary seals ~and a fourth vapor seal. , , The primary seals actwf to break down RCS pressure in 3 equal , stages of approxima"ely 750 psid. The seal stages segregated
- the seal package into 4 cavities, the lower (below the lower i seal), the middle (between the lower and middle seals), the upper (between the miodle and upper seals), and the controlled
- bleedoff (between'the upper and vapor seals). Each seal was rated for full RCS pressure. The pressure breakdown process resulted in a controlled bleadoff flow to the VCT of
] approximately I gpa per pump. Seal injection into the lower
- seal cavity. was possible via the CVCS system,. however, the ;
licensee discontinued routine use of seal injection in 19g3
- (via safety evaluation JPN-PSL-SENJ-93-001) following indications that the cooler injection water led to damage of i 4
RCP shafts. The seals were cooled and lubricated by controlled bleedoff flow which was cooled by a combination of ] the thermal barrier heat exchanger (below the seal package) and a seal water heat exchanger (which cooled flow rising from the RCP casing driven by an auxiliary impeller affixed to the pump shaft).- '
- j. Seal Failure On August 2, while performing a Unit I heatup following
. Hurricane Erin, operators noted that the middle seal cavity of
- the IA2 RCP indicated a pressure which approximated RCS j pressure, indicating a failure of the lower seal of the package. Operators subsequently entered ONOP l-0120034, Rev 34, " Reactor Coolant Pump," which required, upon j ,
identification of a failed seal, that seal pammeter data be
- recorded every 30 minutes to ensure that additional seal stages were not degrading.
- .Throughout the day, the licensee considered the option of
" restaging" the seal package. The process involved opening vents associated with each seal cavity in an effort to increase the differential pressure across each seal stage which, in principle, would force moving and stationary seal
- faces together more tightly, thus reestablishing the seal.
The evolution was described in OP l-0120020, Rev 72, "Fillir.g and Venting the RCS," Appendix '., " Restaging Reactor Coolant Pump Seals.". l According to various personnel in the licensee's Operations organization, the process had been successfully applied i several times in the past. The licensee opted to perform the
- procedure, and informed the inspector of their inteations.
e ___= . . - - , _ _ . . _ . .--a. ,c_y. ,-,-.
I 4 i
< The inspector was not familiar with the process; however, in discussions with the licensee, the inspector was informed that the process had been performed satisfactorily in the past, j that a procedure existed for the process, and that experienced :
- ANPSs, who had performed the procedure in the past, were being '
assigned to the task. j
\
- At 5
- 17 p.m. on the same day, the licensee began the restaging i
~ ~
process. Plant conditions at the time were Mode 3,1450 psia, l
- 370*F, with RCPs in operation. Per the governing procedure, l
. the controlled bleadoff cavity was vented, followed by the i' upper and middle cavities. At this point, flow out the vents 1 was expected to decrease as the lower seal stage restaged; l
- however, flow did not diminish and, after approximately 1 3 j minute, black material was noted to be in suspension in the ;
- vented reactor coolant from the middle cavity. Additionally, ;
3 the water temperature was noted to increase rapidly. l Operators closed the middle cavity vent valve and noted that, almost immediately, black, hot, water issued from the upper ! seal cavity vent, indicating a middle seal failure. Operators immediately closed the vent valves associated with the upper
. seal cavity and the controlled bleedoff, cavity. !
\
At 5:50 p.m., control room differential pressure indications j were received which confirmed that both the lower and middle l seal stages had failed. Controlled bleedoff flow increased to l
^
greater than 3.5 gps., which indicated degradation of the j upper seal. At 6:10 p.m., a cooldown and depressurization of
, the unit commenced. At 6:40 p.m., the IA2 RCP was secured and , lower seal cavity temperatures were noted to increase to 300*F due to the increased leak rate through the seal package and . the lack of aaxiliary impeller-driven cooling (as a result of securing the pump).
A. MSI3 Actuation As the cooldown proceeded, SG pressure decreased and, at approximately 700 psig, annunciators Q-18 and Q-20, ;
"MSIS Actuation Channels A/B Block Permissive,"
illuminated. These were expected alarms, as cooldowns naturally result in SG pressure decreases below the MSIS setpoint. MSIS block keys were provided for this ; eventuality to prevent MSIS actuations under non-
. accident related conditions of low SG pressure.
The desk RCO, who was performing cooldown-related duties : at the subject area of the control panels, acknowledged - the annunciators and later reported observing that the MSIVs and MFIVs were in their post-MSIS positions as a function of the cooldown. fonsequently, the RCO elected
' not to insert the MSIS block and returned to VCT degassing operations. The RCO was then questioned by an 2 ,
i 4
W 1 l
!- 'STA as to the failure to block - the MSIS. The' RC0 i responded that, as the MSIVs. and MFIVs were in their i post-trip positions, the actuation would not present a
j problem. The board RC0 (the second of the two RCOs ; i performing the cooldown) became involved and directed
. that the MSIS be blocked. .Sefore- the keys could be '
i inserted to block the signals, SG pressure fell below the actuation setpoint and an MSIS was received. The i- signal was later blocked and reset. ! i The inspector reviewed HPES g5-07, Rev 2, the licensee's review of the~ event. In it, thenlicensee determined that, in " Summary of Factors that Influenced Human Performance," the event was the result of a lack of !- knowledge on the part of the desk RCO that an MSIS was reportable to the NRC whether or not components changed ' state. Under " Summary of Causes," the licensee cited i the following causal factors: 1-
- Training / Qualification:
i The licensee determined that training had not
- educated operators as to the reportable nature of ESF actuations, whether or not components changed state.
l.
- Supervisory Methods - Progress / Status of Task not
! Adequately Tracked: The licensee determined that the ANPS and NPS
! , were too involved in the diagnosis of the RCP j
- seal failures and were not observing the overall <
i cooldown in progress at the time.
. Work Practices -
Pertinent Information not 1 Transmitted: 1 The licensee determined that the desk RC0 did not
- announce to the rest of the control room that the annunciators had been received; thus, ANPS/NPS
~
, involvement to establish the MSIS block was not ,
obtained. 1
= Work Practices -
Document Use Practices - Documents not Followed Correctly: ' The licensee determined that OP l-0030127. Rev 68, " Reactor Plant Cooldown - Hot Standby to Cold 1 Shutdown," contained a step requiring the operator to block the MSIS when the permissive was received; however, the step was contained further into the procedure than the operator had proceeded. Additionally, the licensee determined that ~ the operator had failed to refer to the + annunciator response procedure, which directed that the block keys be inserted. 3 i. l
The licensee's proposed corrective actions for this - event included: 1
- Revising operator training to include "the ;
necessity - to block ESFAS and other reportable l actuations when they al arm. . .The plant's operating philosophy of keeping Licensee Event ; Reports to a minimum should also be included and l stressed."
- Including the event in Licensed Operator :
Requalification Training. t
- Emphasizing that control room management should maintain a' " big picture" view of plant evolutions, that formal crew communications
. should be employed, and that procedures are followed. ,
The inspector concluded that the licensee's investigation was e nk in that:
- The operator's knowledge of procedural requirements prior to the event was not reported (i.e. did the operator know that the OP l-0030127 required that the MSIS be blocked?).
- The conclusion that' the operator's lack of knowledge of the reportability of the MSIS :
actuation was a principle . contributor to his actions appeared to place more importance on
, avoiding an administrative / visibility burden (i.e. reporting actuations to the NRC) than it did on knowledge of, and adherence to, procedural >
requirements. , The inspector discussed the subject report with the : licensee. Operations management stated that the operator in question reported being confused at the time , and that it was their expectation that, under such circumstances, operators would refer to the annunciator response procedures provided for each annunciator panel. Management further stated that it was not their : expectation that RCOs would be familiar with NRC reporting requirements (this knowledge was said to be the responsibility of ANPS/NPSs and STAS) and that l operator actions should be based upon procedure i
- requirements, as opposed to reportability.
The inspector reviewed OP l-0030127 and found that step I 8.21 -directed that "At 700 psia S/G pressure, Annunciators Q-18 and Q-20, MSIS Actuation Channels A/B 4 l 1
)
I l i -
- m ,
l Block Permissive, will alarm.' Block MSIS by placing -] MS!S block key switch to BLOCK position." Additionally,
; ONOP 1-0030131, Rev 60, " Plant Annunciator Summary,"
specified that, upon valid receipt of annunciators 0-18 and Q-20, operators were to immediately . block MSIS ) channels A and 8, respectively. The inspector concluded i
- that the failure of the Desk RC0 to perform step 8.21 of !
4 OP l-0030127 constituted.the first example of a l
- violation. (VIO .335/95-15-01, " Failure to Follow
- Procedures," Example 1).
e Following the' MSIS, the cooldown was temporarily suspended. At approximately 8:18 p.m., an annunciator was received 3 indicating that reactor cavity leakage exceeded I gps. l Operators verified that control room instruments indicated an
- increased leak rate from approximately .25 gpa to ,
, approximately 2 gps. The leakage was identified as being J related to the IA2 RCP vapor barrier. Operators entered ON0P ^
i 1-0120031, Rev 23, " Excessive Reactor Coolant System Leakage," l at 8:24 p.m. At 8:44 p.m., safety function status checks were completed satisfactorily. At 9:25 p.m., the licensee declared
- an Unusual Event based upon occurrences that warrant increased awareness, specifically, due to concerns over further RCP seal '
degradation. At 6:30 a.m. on August 3, the Unusual Event was 4 terminated based upon the reduction in RCS leakage through the IA2 RCP seal (due to depressurization) and on stability of plant conditions. t The licensee performed a cooldown/depressurization of Unit 1 i and replaced the subject seal package.- The failed package was then disassembled. in an attempt to determine the root cause
, for the failures. At the close of the inspection period, the !
licensee had.not concluded its root cause investigation. The inspector discussed the effort with the licensee. The most , probable root causes for the noted conditions were described i as follows: !
- The most probable root cause for the indicated failure of the lower seal was destaging.- Upon restaging, the 4
~ carbon face of the lower seal was believed to have been forced, rapidly, against its mating seal face, resulting 4 in fracture. 4
- . . The most probable cause for the middle seal failure and degradation of the remaining seals was stated to be a 4
i reduction in cooling and lubricating flow though the seal as a result of the venting of the seal cavities. The subsequent torque, imposed due to pump rotation without lubrication, fractured the middle seal rotating face. Following the failure of the IA2 RCP se,a1 package, the PGM 5 l
- n - em _e -- - - - . - - . - - ee< w
o E q i initiated STAR 950849 to perform a self-assessment of the - decision making proces that led to the restaging of the seal. ! The conclusions reached in the self-assessment were that the : i one-on-one nature of the decision making process precluded a
- " synergistic environment." The study went on to state that,
- while several individuals expressed concern over the prospects for success, no specific technical issue was raised. The licensee determined. that. the existing' Nuclear Policy 105 process, which required multidiciplinary review of prnposed abnormal activities, should be expanded such that it is employed when questions of procedure applicability are raised.
f The inspector reviewed available information regarding RCP. j ,
, seals and restaging. The following was noted: j t
OP l-0120020 Rev 72, " Filling and Venting the RCS,"
- j contained, in the base procedure, precaution 4.2 which ,
- stated."Do not attempt to vent if the RCS temperature is 1 above 200*F." Initial conditions specified in the base i
. procedure were consistent with the Cold Shutdown mode of . l ! operation.
- OP l-0120020, Rev 72, " Filling and Venting the RCS," )
Appendix E, " Restaging Reactor Coolant Pump Seals," included only two statements that could be construed as initial conditions or precautions. One was in the form of a note and the other in the form of a caution. The note stated " Ensure semi injection is aligned and in service." The caution stated "If RCS is greater than 200*F, Then use caution when venting."
- FSAR section 5.5.5.2 stated that the vapor seal was :
designed to withstand RCS operating pressure when the RCPs were idle.
- The restaging process described in Appendix E to OP l-
. 0120020 was substantially the same as the -seal package venting procedure described in the vendor technical manual for the RCP. However, the venting procedure in the technical manual directed that the venting be performed at approximately 200 psi with an idle pump.
- Safety Evaluation JPN-PSL-SENJ-93-001, Rev 1, " Deletion :
, of RCP Seal Injection," included, by reference, FPL letter L-81-107 to the NRC reporting test results for .
RCP seals in postulated- station blackout conditions. ' The resuits of the tests were that, under simulated Hot Standby conditions, a maximum of 16.1 gph was recorded after 50 hours without cooling water flow to the seal - package.
- The vendor recommended a maximum seal package 6
f
- ~ .- - - -. . . - - - . - - _ . - . . - . - -. - - - _
. temperature of 250*F based upon the rubber components in i the seal package. Safety evaluation JPN-PSL-SENJ-93-001-provided analyses to increase the temperature limit to 300*F.
~
- The - licensee produced a Byron-Jackson letter, dated i November 16, 1990, which reported a review of St.
L . Lucie's proposed restaging process. The letter stated 1 that the proposed process was acceptable. The letter 1 also stated - that application. of the process should j . consider. initial seal condition and age in determining whether to apply the 'rocess. p , The inspector concluded that the licensee had reason to believe that restaging the IA2 RCP seal package would correct i , the identified condit' on. Vendor information and knowledge of
- previous successful restagings tended to support the evolution. However, the inspector found that the procedure appendix which directed the evolution did not require initial conditions sufficient to ensure that seal package temperature limitations would be observed. In fact, the " Caution" i statement of the Appendix (advising caution if RCS temperature l exceeded 200*F) ran counter to precaution. 4.2 of the base procedure (precluding venting if RCS temperature exceeded 200*F) . Absent any modifying information in Appendix E, the ;
inspector concluded that the initial conditions specified in ' the base procedure applied to the procedure and its appendices. Consequently, the failure of the licensee to adhere to the initial conditions specified in OP l-0120020 is an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 2). The inspector noted that control room logs did not' reflect the alignment of seal injection, while'the note of Appendix E of OP l-0120020 required seal injection. When questioned, the licensee stated that seal injection was not aligned due to concerns for the affect it might have on the RCP shaft. When asked why a TC had not been made to the Appendix, the licensee had no explanation. The licensee's failure to align seal injection to the 1A2 RCP prior to restaging the pump's seal is
..an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 3).
. The inspector reviewed ONOP l-0120034, Rev 34, " Reactor Coolant Pump," and found that, while actions were described for the failure of one RCP seal (30 minute readings to ensure degradation is not occurring - step 7.2.8.C), and more than one RCP seal *(unit shutdown, secure RCP when TCBs open - step 7.2.8.D), no actions were specified for the instance when 3 seals had failed. As stated above, the fourth, vapor, seal was only designed to contain system pressure when an RCP is idle. The failure of DNOP l-0120034 to direct the securing of 7
an RCP when 3 seals have failed was found to be' in ! t contradiction to the design parameters of the RCP. The inspector brought this to the a.ttention of the licensee. The !
- licensee reviewed the issue and stated that PCRs would be i prepared for the RCP off-normal procedures .for each unit, !
! adding a requirement to trip the unit and secure the affected )
- j. RCP should third stage seal failure occur. j In conclusion, the inspector found that the activities relating to the failure of the lower seal of the IA2 RCP were poorly considered in that the restaging process was applied in inappropriate plant conditions. The failure to establish proper initial conditions for the restaging was found to 1
exacerbate the seal's already degraded condition. The ;
- inspector further concluded that two examples of procedural i noncompliance were associated with the seal restaging effort j
- and that one example of procedural noncompliance was '
associated with the MSIS actuation. The licensee's evaluation of the MSIS actuation was found to be inappropriately focused 4 on event reportability, as opposed to procedure compliance. The licensee's self-assessment of the decision making process that led to the restaging of the IA2. RCP was found to be commendable. OP l-0120034 was found to include inconsistencies between the base procedure limitations and those found in Appendix E of the same procedure. A weakness was identified in ONOP l-0120034, in' that design limits of the RCP seal package vapor seal were not properly incorporated into the procedure. .
- 4) Reduced Inventory for RCP Seal Replacements
. On August 5,, Unit 1 entered a reduced RCS inventory condition to support RCP seal replacement work. The following items were observed during this evolution:
. Containment Closure Capability -
Containment was established and maintained during the evolution. The , equipment hatch had been open prior to draindown, but it was replaced, and 'the personnel hatch cloted, once equipment required for the RCP maintenance was in containment.
- RCS Temperature Indication - Normal mode 1 CETs were available for indication.
- RCS Level Indication - Independent RCS level indications were available. A Tygon tube level indicating standpipe in the containment was manned during the draindown and :
was displayed, via closed-circuit television, in the
. control room. The inspector walked down the tygon standpipe and verified it to be correctly aligned and -
free of obvious kinks which would adversely affect its 8 I B w- ,w,.- -
r n 4
; operation. Additionally, a wide range pressurizer level '
transmitter provided level and trend indications in the , control room. i e, RCS Level Perturbations - When RCS . level was altered, additional operational controls were invoked. At plant - daily meetings, operations took actions to ensure that
- maintenance did not consider performing work that might effect RCS level or shut down cooling. -
- RCS Inventory Volume- Addition capability -
Three
- charging pumps and a HPSI pump were available for RCS j addition.
- RCS Nozzle Dans - Due to the type of outage, the nozzle . r
- dans were not installed this time.
{
- Vital Electrical Bus Availability - Operations would not.
- release ' busses or alternate power sources for work
- during this evolution. Both EDGs were operable, as were ,
- all offsite power sources.
l
- Pressurizer Vent Path - The manway atop the pressurizer has been removed to provide a vent path.
l The inspector observed control room activities during the RCS
- draindown to reduced inventory conditions. The evolution was
- performed in accordance with OP l-0410022, Rev 21, " Shutdown 4
Cooling," Appendix A. ". Instructions for Operation at Reduced Inventory or Mid-Loop Conditions," and OP 1-0120021, Rev 38,
" Draining the Reactor Coolant System." The inspector verified . that specified conditions were met prior to the evolution.
1 The inspector found that operators controlled the evolution . 1 well, that appropriate cross checking between level ! indications were performed, and that procedural requirements , for waiting periods between draining stages were met. The licensee exited reduced inventory conditions following the RCP seal replacements on August 7. I Shutdown Cooling Relief Valve lift 5). A. Background 1
. On February 28, while placing the 1A SDC train in service, the licensee experienced a lift of 1A LPSI pump suction relief valve V-3483 (see IR 95-04). The valve did not reseat, and the loss of RCS inventory was abated by closing LPSI hot leg suction isolation valves V-3480 and V-3481, which isolated the relief valve from RCS g pressure. The root cause of the lift was determined to
. be water hammer, which resulted from passing relatively hot RCS fluid through the suction line at high velocity 9 p i
. ~ ~ - .. ._ .. .~. . . . ~ . . - - ~ ~. -- .n~~~..-__ -. .
as the' LPSI pump was started. As corrective cetion, the - licensee revised OP l-0410022 " Shutdown Cooling," to change the methodology of starting the LPSI pump to the
- following
- Shut LPSI pump discharge isolation and LPSI
. header isolation valves
- Start the LPSI pump
- Immediately open the LPSI pump isolation valve
- Throttle open two LPSI header isolations to 150-gpm per header
- Run for 15 minutes
- Start the second pump
- Throttle open the remaining LPSI header isolation .
valves to 150 gpm per header
- Wait 5 minutes
- Incrementally open header isolation valves to obtain full flow.
The licensee reasoned that this methodology would result in a slow increase in flow, allowing controlled system heatup and minimizing the potential for water hammer. 4 B. LPSI Discharge Isolation Valve Lift ,
- On August 10, while placing the Unit 1 SDC system in service to support a cooldown required due to inoperable PORVs (see IR 335/95-16), ' V-3439, the A LPSI header thermal relief, lifted resulting in a loss of approximately 3500-4000 gallons of RCS, coolant in the Unit 1 Pipe tunnel. The following timeline was l developed from operator . interviews, logs and instrumentation data: ,
0018 A LPSI pump start (ANPS, NWE, Logs) Pressurizer level begins to drop (strip chart ; data) 0025 ANPS directs SNP0 to tour pipe tunnel due to i minor reduction in pressurizer level (ANPS) ! No increases in HUT, RWT, ett noted (ANPS) SNPO reports no unusual conditions in pipe tunnel t 0105 'B LPSI pump start (ANPS, NWE, Log) - Pressurizer level recovers and oscillates (strip' chart) ; 0140 Cooldown flow established (ANPS, NWE) i 0210 Fire watch calls control room, reports water ; issuing from watertight door isolating pipe tunnel from RAB (ANPS, NWE) ; 0215 SDC secured (ANPS, NWE) ! Pressurizcr level increases and stabilizes (strip , chart) , 0226 Floor drain isolation valves (FCV 25-1 through 7) ' 10
.- __._.m_ __.__._.____________m_ _ . _ _ _ _ - =. - -
h
1 i , , 1.
)
i - noted to be closed on control panel (ANPS, NWE) Drain valves subsequently opened (ANPS, NWE) ,
- Flooding in RAB ON0P entered (ANPS) ,
L Water levels in pipe. tunnel weren't dropping due
- to clogged floor drains (NWE) l 0345 Water in pipe tunnel pumped by maintenance i personnel to floor drains in RAB (ANPS)
- Operators cycle various isolation valves looking 2 for leak -
0611 1A LPSI pump started with NWE observing in pipe tunnel (ANPS) 4 0612 NWE identifies V-3439 as passing water (ANPS) 4 1- The licensee concluded that the cause of the relief , i valve lift was a pressure surge while LPSI pumps were , operating in a low-flow condition. The combination of
- . RCS pressure (a maximum of 267 psia at the time) and 1 LPSI pump discharge head at essentially' no flow
! (approximately- 182 psid) combined with possible perturbations (when starting-the pump) was considered i enough to challenge the relief valve setpoint (485-515). d This condition existed from the time the IA LPSI pump j discharge isolation valve was opened until operators * ;
- initiated flow through the LPSI header isolation valves.
! V-3439 was designed to' provide a 10 percent blowdown, which, if applied to the lower acceptable lift'setpoint of the valve (485. psig), would require a 48.5 psi.a i reduction in pressure to allow resent. Given' these . parameters,.should V-3439 open, RCS pressure would have i to drop to 436.5 psia to allow valve resent (assuming
- only a 10 percent blowdown). The volume of the RCS and .
- ' pressurizer would preclude such a resent until !
significant volumes of coolant were lost. 4 , The volume of coolant lost 'during the event was estimated by the inspector, based upon floor layouts as displayed on drawings. Given water depths reported by l the NWE (up to approximately 14" in some areas), the j inspector estimated that approximately 3500 gallons were ' lost. The CVCS makeup integrator, measuring volume added to the VCT in maintaining pressurizer level on
. setpoint, indicated that 4000 gallons were added to the VCT.
The licensee concluded that the closed floor drain isolation valves, HCV-25-1 through 7 (a set of 7 ganged valves) were the result of valve stroke testing in preparation for Hurricane Erin. During testing conducted by control room operators, some of the valves had failed to stroke properly. As a result, the valves 11
- - , % - , . - , . ,m, - . - -- ,
_ _ _ - - - _ -. ~_ - .. . _ _ . - - .. - -.. - . . -
-.-.7
- i. . were left closed for troubleshooting and were - never -
reopened. OP l-0010123, Rev 99, " Administrative Control
- of Valves, Locks, and Switches," required, in step
- 8.1.6, that "All. valve or switch position deviations or L lock openings shall be documented in Appendix C, Valve Switch Deviation Log..." The inspector. reviewed
' archived Appendix C logs completed in July and August and control room open Appendix C . logs and found no evidence that HCV-25-1 through 7 were logged as being .
- out of position. The failure. to enter the valves' l closed status into the valve deviation log' is an example )
of -a violation (VIO 335/95-15-01, " Failure to Follow l
- Procedures," Example 4). STAR 950917 was initiated to I develop a PM for verifying that floor drains were unclogged.
The lii:ensee prepared: an evaluation of the effects of the subject-setpoint/ blowdown values on plant operation. ! JPN-PSL-SENP-95-101, Rev 1, " Assessment of the Effects on Plant Operation of Lifting the LPSI Pump Discharge : Header Thermal Relief Valve," concluded that the subject , condition would not have a significant effect on safe 4 plant operation during normal', shutdown, and design . . basis accident conditions. In reaching this conclusion, ! the evaluation noted the following:
. As flowrate through the relief valve (at lift setpoint pressure) was approximately 40 gps, the i
loss of. inventory was within charging system capacity (44 gpa per pump). i
- During the injection phase of an accident, the LPSI pumps would draw. suction from the RWT, thus pressure developed by the pump would not compound a high pressure suction source and the relief valve's lift setpoint would not be challenged.
- The relief valve in question discharged to a floor drain which directed flow to the safeguards room sump. The sump was designed to be pumped down in level to the EDT automatically when offsite power is available. Thus, with offsite power available, no flooding hazard would exist.
, , Under conditions with no offsite power available, the water level in the safeguards room (after the sump overfilled) would not rise to the. level of the HPSI pump motors until approximately 7 hours
.after the lift. Before this time elapsed, the licensee reasoned that sump high level alarms would alert operators to the event,. allowing operator intervention prior to the loss of the HPSI pump.
12
\ > l'-
- The. licensee noted that, while soc was assumed to be placed in service during postulated small
- . break LOCAs, ESDEs, and SGTRs (when RCS pressure may have been high enough to have led to a relief l valve lift), the FSAR analysis demonstrated that fuel damage (and thus the release of significant amounts ~ of radioactive material to the RCS) was
. involved only because of extremely conservative-assumptions. The evaluation went on to state that "A review of FSAR analysis of small break LOCAs, ESDEs and SGTRs demonstrates that these accidents will' not result in fuel damage if assumptions that reflect the actual operating history of the plant are applied. Therefore, the -
radiological consequences of these FSAR accidents will not be ir. creased and the FSAR offsite doses remain bounding." The inspector took exception to the licensee's conclusion. The subject passage was included in Section 4 of the evaluation, " Analysis of Effects of Lifting V3439," in a section entitled " Increases in Radiological Consequences of Design Basis Accidents." The inspector found 'that, in choosing to neglect design basis assumptions in their analysis of the event (specifically, a return to power and fuel failure resulting from the most reactive rod failing to insert), the licensee did not evaluate the increases in the radiological consequences of design basis accidents. ' Rather, the licensee evaluated ~ the radiological consequences of a less significant set of accidents and concluded, without providing quantitative results, that the radiological consequences of design basis accidents ] bounded the noted relief Yalve lift. While the ! inspector agreed with the licensee's position that the I circumstances assumed in design basis accidents were, i probablistically, of low likelihood, the inspector , pointed out that the assumptions were the approved ] licensing basis of the plant and, as such, provided the ! appropriate common ground upon which to evaluate the ; event's significance. The inspector brought this to the i attention of the licensee, who stated that they would consider the issue. At the close of the inspection period, the licensee had not presented a final position on the issue. As a result, this issue will be tracked i as an unresolved item (URI 95-15-04, " Adequacy of i Engineering Evaluation Regarding Unit 1 Loss of Inventory via V-3439"). On August 12, the inspector requested data on approximately 25 relief valves on both units which communicated with the RCS in some way. The requested 13 : i
- e t
' data included'11ft and blowdown setpoints, tolerances, -
relief capacity, and normal operating pressures experienced by the valves. Shortly after requesting the information, the licensee informed the inspector that a team had been fomed to . evaluate all . safety-related relief valve data. - The team included member. from , Engineering, Maintenance,-Dperations, Tech Staff, and Licensing. . 9 The team's review was documented in JPN-SPSL-95-0334, "St. Lucie Units 1 and 2 Design Review of Safety Related - Relief Valves," transmitted to the site by letter dated August 30. The inspector found the methodology of the , study to be sound, considering worst case combinations of system operating pressures, relief valve setpoint, and blowdown. Relief valves were evaluated for their i margin to . lift - and blowdown margin (the difference : between resent pressure and normal system operating : pressure).. The document reported that, of 114 relief . valves reviewed, 8 valves on Unit I and 5 valves on Unit
. 2 required further review due to unacceptable margins of lift or blowdown. Corrective Actions were specified for the following valves:
Unit 1 Valves 4
- V2324. V2325, and V2326 - Charging Pump Discharge >
Relief Valves - MEP 107-195M was issued to reduce the design superimposed backpressure from 165 psig to 115 psig. .
- V2345 - Letdown Relief Valve - PC/M 108-195 ,
issued to reduce letdown backpressure to 430 psig and to reduce the valve's blowdown from 25 percent to 15 percent.
- V3412 - HPSI 1B Discharge Header Relief Valve -
- EP 115-95 was issued to increase the design setpoint from 1735 psig to 1750 psig and to ,
reduce blowdown from 25 percent to 10 percent.
- V3417 - HPSI Pump 1A Discharge High Pressure Header Relief Valve -design setpoint increased ,
from 2400 psig to 2485 psig and blowdown reduced l ! from 25 percent to 15 percent.
- V3468 and V3483 - SDC Suction Relief Valves -
STAR 950430 was issued to evaluate new setpoints and blowdown anes. Unit 2 Valves 0
'14 ;
( m 7
l L. V2345 .- Letdown Relief Valve - At the close of the inspection period,- ari EP was being prepared
. to implement actions similar to those implemented
~
on Unit I for this valve. l
- V3412 - HPSI 28 Discharge High Pressure Header l
! Relief-Valve - At the close of the inspection l period, an EP was being prepared to reduce blowdown from 25 percent to 10 percent. i
- V3417. - HPSI Pump 2A Discharge High Pressure Header Relief Valve .- Atn the close of the i inspection period. an EP was being prepared to 4
increase the valve's setpoint from 2400 psig to 2485 psig and to reduce blowdown from 25 percent 4 to 10 percent. l
- V3439 and V3507 - Low Pressure A and B Discharge 2
Relief Valves - At the close of the inspection
- period, an EP was being prepared to increase the valve's setpoint from 500 psig to 535 psig.
,' As a result of the licensee's investigation, and through discussions'with vendors, the licensee determined that i seee relief valves had been provided with unacceptably higi; blowdawn values. This was, apparently, due to procedural problems at the vendor's test facility. At i the close of the inspection period, the vendor (Crosby) was considering the 10 CFR 21 ramifications of the issue. The licensee documented the conditions on STAR 1 951024. The inspector reviewed the STAR and noted that j it had not been identified as an ".N" STAR (indicating a
- nonconforming condition). The inspector brought this to .
- the attention of QC, and the condition was corrected.
The licensee identified the affected relief valves and segregated them appropriately. j I The inspector reviewed the licensee's STAR database for events similar to the subject event and found the
- following
- ,
i STAR 2-950167, initiated February 20, documented the lifting of SDC heat exchanger CCW relief l valve SR-14350 whert stroking CCW "N" header 4 isolation valves closed. Once open, the relief valve had to be isolated (by closing an upstream valve in the process line) to bring about a i reseat. i
- STAR 0-950234, initiated March 2, documented the fact that relief -valves had lifted and that '
; blowdown values placed the resent pressure of the ;
15 l i I O
. valves in the operating ranges of the systems they protected, j
- STAR 1-950269, initiated March 10, documented relief . valve lifts on the Unit I CVCS letdown line during evolutions which should not have challenged the valve's setpoint.
- STAR 0-950917, initiated August 18, documented the subject SDC relief valve lift.
In addition to the STARS referenced above, IR 95-05-01 discussed work performed on the Unit 2 CVCS system to prevent letdown line relief valve lifts. The -IR also described the failure of the relief valve to ressat (once lifted) due to a blowdown value which placed the reseat pressure below the system's normal operating pressure. j The inspector reviewed the status of the STARS listed above and found them all to be open. The inspector ) discussed the timeliness of the resolutions to the ' subject STARS with the licensee. The licensee stated , that their focus had been on the methodologies for j setting blowdown values on the valves in question, l rather than on the appropriateness of the setpoints themselves. The licensee offered STAR 950234 as being illustrative of. this point. The proposed corrective actions included:
- Completion of SRV test benches, wtiich would nilow ,
, the licensee to better set and test SRVs for lift l setpoint and accumulation. It was noted that the bench had only limited blowdown test capability. , l
. Performing an engineering design basis review of l . all safety related SRVs to validate or correct )
setpoints and issue a ' design document that : summarizes the design data. l
- Enhancing journeyman training on SRVs.
While the inspector found the licensee's proposed
, activities prudent, it was noted that nothing precluded engineering from addressing the setpoint issue earlier in the process. The licensee stated that the STAR was addressed in stepwise fashion and that the maintenance-related items were addressed prior to forwarding the STAR to engineering.
The inspector found that the licensee's corrective actions for the subject event were comprehensive and l l 16 I
.___.__________________________j
l . l. l l '
' sound.. However, the inspector concluded that ' the actions could have reasonably been expected to be ,
performed.in a much more timely fashion. The subject i i phenomenon was identified as early as February,1995, , and repeated itself on no less than 3 separate systems,- , and on both units, prior to the most recent event. Once focused -on the issue, an engineering product of high , quality was developed, and corrective actions initiated, ' j in approximately 2 weeks and identified valves requiring i attention in a comprehensive action. 10 CFR 50, Appendix B required that, for conditions adverse to quality, prompt corrective action be taken to prevent i' recurrence. The licensee's failure to take prompt corrective action to the February / March events is a
- violation (VIO 335/95-15-02, " Failure to Take Prompt Corrective Actions for Repeated Relief Valve Lifts").
- 6) Containment Spraydown A. Background
] . The St. Lucie Unit 1 LPSI and CS systems are shown in i Figure 1. The two systems are interrelated in that they ' share the SDC heat exchangers. In an accident mode, the
- SDC heat exchangers serve to cool water drawn from the containment sump prior to delivery to the containment environment via. the containment spray headers.
Referring to Figure 1, the accident mode flowpath for - CS, train. A, involves water traveling into the A CS l pump, through the SDC heat exchanger, and to the A CS
- header in containment. In a SDC mode, the SDC heat exchangers, in conjunction with the LPSI pumps, serve to a remove heat from reactor. coolant. The flowpath in this j mode (again, for the A train) involves water flowing from the RCS hot leg and through the A LPSI pump. The fluid flow is then split at FCV-3306, with some water-
, passed through the valve and the balance diverted j through the SDC heat exchangers, through MV-3456 and/or MV-3457, and returned to the LPSI system for delivery to
- the RCS cold legs.
During power operations, the two systems are isolated i from one another and each is aligned to perform its
, safety function. In the case of the CS system, this alignment involves an open flowpath from the RWT, ) through the CS pumps, and up to FCV-07-1A and FCV-07-1B, normally closed A0Vs' which receive open signals in response to a CSAS.
B. LPSI System' Venting i In February, the licensee experienced a waterhammer 17 } f
-y q % n mv m ---y-- -mt-p. y,+ __
C event in the Unit 1 LPSI system while placing SDC in " service (see IR 95-04). The licensee determined that one of the potential contributors to the event was air,-
- trapped in system piping. At approximately the same, j
'the licensee ~ identified a Unit 2 LPSI pump -in an air j bound condition during a surveillance run of the pump.
- In response to these events, the licensee developed aggressive venting programs for the systems. As a part of the effort, OP l-0420060, " Venting of the Emergency i'
- Core Cooling and Containment Spray Systems," Was j developed. The procedure' required, in part, that
. venting be performed following SDC system operation. - The procedure was approved on August 13. As a part of the venting procedure, the licensee pressurized the lines leading to the SDC heat exchanger . , via the LPSI pumps and systematically directed flow to j the RWT in an effort to sweep air from the system. The i 4 boundary of this venting process included the CS lines l up to the CS header isolation valves. ! C. FCV-07-1A Inoperability l . On August 11, CS flow control valve FCV-07-1A failed a
. stroke time test and was declared 005. As shown on
! Figure 1, the valve isolated the A CS header from the CS ! system outside containment. The valve was designed to ! open on a CSAS and was a fail-open A0V. The valve was required by AP l-0010125A, Rev 39, " Surveillance Data , Sheets," Data Sheet 8A, " Valve Cycle Test - Non-Check Valves," to stroke in less than 8 seconds. In the
, failed test, the stroke was recorded as 20.3 seconds. l
' As a result of the failed surveillance test, STAR 950869 was generated. The stroke time failure'was documented and the STAR was assigned to Engineering for
- disposition. Engineering proposed placing the valve in l its safeguards position (open) and prepared SE JPN-PSL-i SENS-95-016, Rev 0, " Alternative Valve Position for
,_ Spray Header Isolation Valve 1-FCV-07-1A."
1 The inspector reviewed the subject SE. The purpose of the valve and its relationship to containment isolation and containment boundary integrity were found to be appropriately considered. The SE concluded that no i unreviewed safety question was introduced by placing the valve in an open position. The SE went on to provide 3
" required / recommended" actions:
. Administrative controls, consisting of caution tags and the installation of plastic covers over switches, were required to be implemented locally
~
18 1 l
4 J f
+ >- and at the RTGB for CS pump 1A to prevent inadvertent operation of the pump.
1 r -
- Operators were to be informed of the new valve -
alignment with emphasis given to CS pump , surveillances and A SDC train operation.
-
- Procedures were to be reviewed'for impact. The SE stated that, in lieu of procedure changes, administrative controls may be used while the
. valve was open.,
The SE was approved by the FRG on August 12. Upon !- completion of the evaluation, the STAR was turned over i to Mechanical Maintenance with a required action of 1 restoring the valve to original design and to perfers a . } root cause investigation into the failure. The inspector noted that ~ the subject STAR included no indication that the required actions listed above had been completed prior to Engineering releasing the STAR i l to Mechanical Maintenance and prior to Operations repositioning FCV-07-1A. The inspector questioned the STAR coordinator as to who was responsible for ensuring : that the SE's required actions were complete and was j informed that Engineering, as the organization responsible for the resolution, was responsible. The same question was posed to the Engineering Chief Site i Engineer, who stated that the responsibility for completing the action belonged to Operations. The ! inspector reviewed QI 16-PR/PSL-2, Rev 1, "St. Lucie Action Report (STAR) Program," and found that the i procedure was unclear as to who was responsible for
- ensuring the activities were completed. As a result the inspector concluded that a weakness existed in the STAR program with regard to ensuring that required corrective ;
actions were documented and completed. l . \ On August 15,'a Night Order was issued which informed l operators that the unit would be operated with FCV-07-1A i open. The Night Order went on to state "See attached Engineering evaluation which includes actions to be taken to avoid an accidental spraydown of containment." The SE limited its consideration for the potential of l . inadvertent spraydown to inadvertent CS pump starts, 1 except as provided in the second required action summarized above. On August 16, caution tags were hung l and the valve was taken to an open position. D. Containment Spraydown On August 18, venting of the LPSI A train was commenced per OP l-0420060, Rev 0, " Venting of the Emergency Core 19 I
\
s r -- - _. - , - . . _ - ,
- - . - -. .. . . . .~ ._ - -- -- .-
I Cooling and Concainment Spray Systems." When the A train was pressurized through the SDC heat exchangers, the open flow path created to the A CS header through FCV-07-1A allowed water to be drawn from the RWT and 1 sassed into the containment atmosphere. via the spray ; saader.-
. Operators were alerted to the event by an annunciator indicating high reactor cavity inleakage. Indicated flow into the cavity was increasing rapidly and ,
! operators entered ONOP l-0120031, Rev 23, " Excessive t Reactor Coolant System Leakage."- Approximately one minute after the annunciator was received, operators 2 identified the flowpath leading to the spraydown and secured the A LPSI pump. The spraydown resulted in a i, slight decrease in containment temperature and pressure. . The licensee noted that 90 percent of containment smoke
- detectors alarmed or faulted and an electrical ground
- developed in the IA2 SIT sample valve as a result of the event.
- u E. Impact on Unit 1 The licensee determined that approximately 10,000 l gallons of water from the RWT was transferred to
- containment during the event. The water was borated at ;
approximately 2200 ppe. The spray resulted in an i ! increase in contamination 1
- with levels exceeding lx10'dps/100 levels cmins in{de containment, many areas.
! . Following the event, the licensee placed a hold on all work on Unit 1. The unit was maintained stable in Mode 3 and mansgement announced that it would conduct a series t ' meetings with all plant personnel to discuss the rece.. events on Unit I and to reiterate management l expectations for worker performance.. Meetings were held f on August 18 in which the Division President, the Site Vice President, and-the Plant General Manager. stressed i the need for worker vigilar.ce, procedural compliance, and a questioning attitude on the part of all plant personnel. Additionally, plant management made plans to i cool down Unit I to allow for a decontamination of containment, a repair of FCV-07-1A,' and a number of other work items prior to returning the unit to service. . The licensee's initial plans for containment cleanup did not bring the contamination levels to pre-event conditions. After discussions with management, a decision was made to expand the scope of this cleanup
, and decontamination to reduce the need for additional cleanup during the next refueling outage.
20 e
}. V i' . The inspector toured the containment on August Ig. HP l briefings prior to entry indicated that the majority of l the contamination was in a smearable form. Containment cleanup had begun, and guidelines had been developed and promulgated under LOI-HP-23, " Decontamination Following i Inadvertent Spraydown of the Unit 1 RCB." The inspector noted that the 62 ft. elevation of containment had been
- separated into quadrants for initial decontamination.
, While light. water spotting was noted on the outer surfaces of some equipment, no obvious boron deposits were identified. Water was observed to be puddled in upturned I-beams supporting flocr. grating, but floor 4 surfaces were dry.
4 The licensee evaluated the event in Engineering , Evaluation JPN-PSL-SENS-95-017, " Assessment of Inadvertent containment Spray Event." Items considered i, in the evkluation included: i = Boric acid corrosion of carbon steel components, potential effects on EQ and non-EQ instrumentation and electrical equipment. .
- Potential effects on cranes and supports i = Potential effects on snubbers
= Potential effects on containment coatings Corrective actions resulting from the evaluation
. included a comprehensive inspection of components inside
- containment. Included were visual inspections of all snubbers inside containment following containment l washdown for decontamination. The inspection list j compiled by engineering included items to be inspected i by tag. number, the type of inspection to be parformed,
- acceptance criteria, and actions to be perfomed if ,
acceptance criteria was not met. In all, approximately l 1000 individual inspections were performed. Of the i items inspected, only minor deficiencies were identified.
- l F. Evaluation of the Licensee's Activities l The inspectors concluded that the root cause of the containment spraydown event was a failure of OP l-0430060, Rev 0, " Venting of the Emergency Core Cooling ;
and Containment Spray Systems," to require a' ! verification of initial conditions. Specifically, the proceduro failed to verify that the CS system was in an alignerent which was appropriate for the evolution being The procedure was revised to remove the conducted. 21 l i rT- 4 , - m. . . - .
? .
. l
. subject portion, leaving- only static venting, on : September 1, The licensee reached a similar cone usion ; in LER 335/95-007, and added that contributing factors l included operators failing to realize that plant j conditions at the time of the evolution would result in the event. Additionally, the licensee identified that the decision to defer the repair of FCV-07-1A contributed to the event. The failure to include ; appropriate initial conditions in OP l-0430060 constitutes a violation (VIO 335/95-15-03," Inadequate ; Procedural Initial Conditions"). The inspectors reviewed the licensee's corrective actions as they related to containment inspections ! following the event. The inspectors found that the ; licensee's evaluation of the event and the inspection scope resulting from the evaluation was in agreement , with the NRC position on the subject (as described in the NRR DST Safety Evalsation on the subject, transmitted to regional offices via letter from T.E. Murley,on March 13,1991). The licensee's inspection was determined to be comprehensive in scope and detail and adequate to ensure future component reliability. -
- 7) Primary Water Storage Tank Overfill On August 19, at approximately 5:30 p.m., the Unit 1 RC0 1 directed the SNPO and ANPO to fill the PWST. At approximately 7:45 p.m. , the " Primary Water Tank Level High/ Low" alarm ,
annunciated in the control room. The RCO directed the SNPO to have the ANP0 secure the fill valve to the PWST while making his rounds. .The decision to delay securing the valve was based on the RCO using a-tank strapping table in the control : room which showed a margin of approximately 1.5 feet from the t high level alarm to tank overflow. At 8:30 p.m., a call was : received from the Unit I containment ramp that the PWST was overflowing. At that time the ANPO and SNPO were directed to immediately secure from filling the PWST. The fill valves were then closed. It was estimated that about eleven thousand gallons overflowed form the tank. Chemistry samples found that no release limits were exceeded as a result this event. L The cause- of this event appeared to be inappropriate and
. untimely operator response to an alarm coupled with an existing operator work around on the level control system for the PWST.
The PWST level control valve LCV15-6 had a history of unreliability. Because of this unreliability, the operator , had been manipulating V15106 or V15105 which are in series with. LCV15-6. If this condition had been corrected, the . system would have been able to automatically maintain PWST l 22 , n
. _ _ . - . - _ _ _~. . . . ___ _ _ _ _ _
< j
\
level.-
- 8) 2A Heater Drain Pump Trip ,
- At 8:20 a.m., on August 23, the "LP Heater 2-4A Level Hi/Lo" !
annunciator alarmed in Unit 2 control room. The operator
. observed that 2A condenser back pressure had increased from . 4.5 to 4.9 inches Hg. Immediately thereafter, the 2A heater 4 i drain pump tripped. The control room operator immediately ; entered ONOP 2-0610031, Rev 13, Loss of Condenser Vacuum, and began' reducing >ower to maintain condenser back pressure to less than 4.0 n Hg. Power was reduced and the unit was stabilized at 82 percent. The inspector responded to the !
[ , control room and observed this power reduction. > An investigation of the event by the licensee found that relay i 63X-4A (a GE HGA relay), common to both the 4A alternate and 5A normal heater drain valves had failed. This failure caused ' i the 4A alternate drain valve solenoid to de-energize and the valve to fail open. It also caused ~the SA normal drain valve to fail closed. These failures resulted in a rapid decrease : in level in the 4A heater and tripped the 4A heater drain J pump. j i .The inspector found that operators response to the event was timely and correct. The failed relay was subsequently replaced. An investigation by the licensee determined that :
; the relay failure was due to aging.- A review of other
- applicable uses of this type relay by the licensee found and j j replaced several other HGA relays in the heater drain system.
l . The inspector noted that at least eight other heater drain ! , pump trips had occurred over the past two years. None of ; these trips were the result of a HGA relay failure. The ' licensees' review of this and other recent HDP trips led them I ^ to install a PC/M in the heater drain pump protection ; circuiting during this outage that should result in a i reduction of these and similar HDP trips. The inspector found that the licensee's corrective action for this event was detailed and thorough. However, taking into consideration the previous number of HOP trips that had occurred and the licensee's knowledge of this problem and the I
. needed changes clearly indicate that corrective action on this l item was not timely. This item is identified as a weakness in l corrective action. I i
l 1 s) Control Room Logs i On August 24, during a review of the Unit 2 control room RCO c log, the inspector noted an entry which stated that 28 EDG had erratic load swings during the performance of the monthly 23
. ,.m. -.. ~ , . . _ . - . _
^
surveillance tests. Further review of the log indicated that I the EDG was taken out of service to replace an air start ) solenoid valve and then tested and' returned to service. The RCO, on the shift after this ites occurred, was questioned on the entry involving the erratic load swings and was not aware l of the cause or any corrective action taken on this potential 3 deficiency. This item was discussed in detail with the system . engineer who was able to satisfactorily address this ites. AP 0010120, Rev 74, " Conduct of Operations," section 2.A.3, requires that problems associated with major equipment be , logged. The inspector noted that the control room log should : have contained adequate information to allow the operator on ' a succeeding shift to clearly understand this potential problem and know if it had been adequately addressed to ensure operability of this ESF component. In addition to the above, on September 1, a review of the Unit : 1005 log found that containment purge valve FCV-25-4 had PW0s 95013857 and 95004327 and STAR 94110479 issued against it. The valve had been placed in the failed closed position but had not been entered in the 00S log. OP 0010129, Rev 24,
" Equipment Out of Service," section 3.2, required that -
inoperable TS equipment that is out of service. be logged. Upon identification by the inspector this item was entered in i' the 005 log. On September 2, the inspector noted that clearance 1-95-009-l - 011 had been issued to deenergize IB EDG fuel oil transfer , pump to permit work on a local switch. A review of the 005 log and control room log also found that this had not been entered in either~as required by the clearance procedure OP 0010122 step 5.6.5. A discussion with the RCO revealed that he did not think this entry was necessary since the EDG was out of service for other maintenance activities. This item was discussed with the ANPS who directed that the appropriate log entries be made. The inspector noted that all of the above items were in a safe l condition and did not affect system operability. These items do indicate a weakness in logkeeping that could result in i operating the plant with equipment out of service that could , be required for that operational mode. This item is
, identified as a weakness in logkeeping and a failure to follow
,, proceduras, and is an example of a violation (VIO 335/95 i 01, "Fa'. lure to Follow Procedures," Example 5).
- 10) Operation of IB LPSI Pump with the Suction Valve Closed i
On August 29, Unit I was in mode 5 with both trains of SDC in > operation. At 2:20 p.m., the B train of SDC was placed in standby to allow a SDC hot leg suction valve leak test to be 24 4 -- _._. .- _ __ _ _ __ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ . _ _ _ _ _ _ . _ _ . _ _
l L- . l performed as specified in data sheet 25 of AP l-0010125A.
- Step 6.5.4.B of this test left one hot leg suction valve V3651 open and the other hot leg injection valve closed at the completion of the test. The SDC normal operating procedure 0P l-0410022, section 8.3, was then used to return the 8 train of I l SDC to service. Instead of using the procedure, the RC0 j
- transposed the procedural steps of section 8.3 to a separate <
4 piece of paper and used this to perform the procedural steps. l Using this guidance he failed to open and lock open B hot leg suction valve V3652 as required by procedure step 8.3.7. * ! T'e'IB h LPSI pump was then started by the board RCO who noted l l the starting surge on the pump ammeter and that the amperes ' had subsequently declined and steadied out at about 15 amperes. The ANPS opened the LPSI discharge valve at the CRAC panel to re-establish flow in the B LPSI loop. The board RC0 i did not recognize that LPSI pump B amperes were lower than anticipated. The board RCO then went to the CRAC' panel to initiate flow to B SDC HX. j l At about 4:45 p.m., the NPS identified that LPSI pump amperes were lower than anticipated. At the same time the desk RCC i found that the hot leg suction valve V3652 was shut. The IB i LPSI was secured and the 'IB SDC train was returned to the , ! standby lineup. A suhtequent inspection of the pump i determined that no apparent damage had occurred during the ! short period of pump operation. After 'an inspection and
- evaluation the pump was returned to service and all parameters
- were normal. An ASME Section XI test was subsequently performed satisfactorily.
i The failure of the operator to follow OP 1-0410022 is an 4 example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 6). This failure could have resulted in t the failure of the IB LPSI pump and subsequent loss of one ! loop of SDC.
- 11) IB Emergency Diesel Generator Failure On August 31, the IB EDG tripped due to high crankcase
- -pressure in the 12 cylinder engine during the performance of the monthly surveillance test, OP l-22000508, "lB EDG Periodic Test and General Operating Instructions." Licensee personnel found that the engine coolant expansion tank had drained and the engine oil sump level had increased approximately eight inches above normal. l Inspection by licensee personnel revealed that the number nine power pack crown and cylinder head had sustained severe damage, apparently due to separation of the northeast exhaust valve head from its stem. The failed valve head became loose within the combustion chamber and during numerous strokes j 25
j punctured the piston crown and cylinder. The engine coolant i then leaked through the cylinder head and piston into the oil and entered the engine sump. The source of the high crankcase pressure tript was a combination of intake air and exhaust gases escapiog through the failed piston into the crankcase. The licensee developed a root cause investigation team composed of personnel from mechanical. maintenance, technical staff, site and corporate engineering, and an engine vendor
- representative. This team performed a detailed investigation over several- days which concluded that the most probable root cause was:
- * (/linder number 9 lash adjuster lock nut loosened. The lash adjuster screw was then 'able to' back out of position due to normal operational vibration.
- As the lash adjuster screw loosened, the hydraulic lifters initially compensated for the increased height
- of the valve bridge assembly. Eventually the increased. l
- height of the valve bridge resulted in impact loading at i the locking ring in the lower spr.ing seat. The locking ring is normally unloaded during operation. l
- The impact loading eventually caused the bridge guide to
- fail. This allowed further bridge movement and loss of
- "zero lash" in the valve train.. The increased clearances resulted in impact loads being transmitted to the valves themselves. The bridge guide failure also increased wear on the guide's lower spring seat.
- The impact loading caused the lock grooves of both east valve spring stems to deform due to fretting wear from
- j. the valve spring seat locks. -The northeast valve spring seat eventually failed due to hoop stresses induced by the wedging action of the seat locks.
- The failed spring seat was retained by the helical
- spring coil which initially prevented valve stem detachment. The additional clearances provided by the failed spring seat allowed the- seat locks to i progressively fail.due to wedging and point loads until
they finally released the valve and allowed it to drop ! i . into the engine cylinder. 1 The valve head separated from the stem due to impact l loading by the piston. The separated valve head was ' then loose in the cylinder and punctured the piston crown and the cylinder head when the piston rose. , Engine tripped on high crankcase pressure due to flow of - , turbocharged inlet air and exhaust gases through the t 26 l
piston into crankcase. Water from broken cylinder head water passages flowed through the piston into the crankcase to drain- the expansion tank. Smaller particles from the piston and cylinder head were blown j into the exhaust ducting. I The inspector conducted daily meetings with the manager of the i root cause team and discussed the status of their
! investigation and. findings. He also observed numerous facets i of the licensee investigation, inspections, and repairs to the
- affected diesel engine.
1 The initial p'lans called for replacement of the number 9 power l pack (cylinder and piston) and inspection of all shaft
! bearings. After inspections found several metal parts from the damaged number 9 cylinder in the exhaust ports of other cylinders and on the engine exhaust turbocharger intake
- screens, the engine inspection was expanded to include all cylinders, exhaust headers, and bearings. This inspection
, found some rust in number 12 cylinder and led to replacing that power pack also. The inspection of the remaining
- cylinders also led to replacing number 3 and 4 cylinder heads
- due to leaking valves.
After the above repairs and bearing inspections, the engine ! was reassembled and flushed with new lubricating oil and all
- filters were replaced. As a result of the root cause
- investigation the lash adjuster locking nuts were torqued to a 50 ft-1bf value given by the EDG service company (this value had not been previously specified in the vendor manual or licensee maintenance procedures). This torquing was accomplished on all cylinders for both the 1A and IB Unit 1 diesel engines. After a series of maintenance runs and adjustments on September 5 and 6, the IB EDG successfully l completed its surveillance test and was declared operable on September 6.
. The inspector found the root causes investigation team to be composed of well-qualified individuals. They pursued the 4 issues associated with the failure in a diligent manner and i worked well with the personnel performing engine repairs. The inspector noted that the licensee's service vendor plans to also perform a root cause investigation of this failure. 1 The inspector was very impressed with the teams that worked the engine repairs around the clock. Their detailed investigation resulted in expanding the scope of inspection and repair to cover the entire engine. The overall repair effort was strongly supported by site and corporate engineering and resulted in timely completion of the repairs.
- 12) Unit 2 Main Generator Hydrogen Overpressurization 27 9
On September 7, at approximately 1:30 a.m., a NPO noted that the hydrogen pressure on Unit 2 generator was at 58 psig. This pressure is normally maintained at 57 to 60 psig. The NPO contacted the RCO and notified him that he would be bringing the pressure up to approximately 60 psig. When the hydrogen sup 1y header was aligned to the generator, control l room annunc' ator "H2. Manf Sply ' Press Hi/Lo" alarmed as ] expected due to low header pressure and remained illuminated. 1 1
. The NPO left the area to continue. his rounds. At' I approximately 2:00 a.m., the control room requested the NPO come to the control room and assist in a digital electro hydraulic loss of load test. This test was completed at about ,
2:24 a.m. The NPO then completed his round and returned to ' his office area. q At about 3:20 a.m., the ANPS noticed that the "H2 Manf Sply Press Hi/Lo" annunciator was illuminated. The RCO checked the hydrogen pressure and found it to-be 80 psig. The RC0 then directed the NPO to secure the hydrogen and reduce the generator gas pressure to 60 psig. Licensee investigation of this event determined that the NPO and control room operators did not apply sufficient detail to the progress of this evolution. The NPO allowed himself to be assigned to another task and lost control of the status of the evolution. The generator hydrogen filling evolution was not adequately tracked by the RCO and ANPS. They also permitted l the "H2 Manf Sply Press Hi/Lo" annunciator to stay illuminated for about two hours when the filling evolutjon should have taken approximately 30 minutes. The licensee also found that
. a generator high gas pressure alarm should have sounded and actuated an annunciator in the control room. The local alarms
. were found to be inoperable with existing PW0s that required t work. ~ This event clearly pointed cut a failure of the NPO and RCO to maintain status while adding hydrogen to the main generator and the failure to reset a control room alarm. - It also showed that an operator must stay aware of the status of alarms on equipment and take compensatory actions if nomal annunciators are not available. This item is identified as a weakness. A subsequent inspection and evaluation by the equipment vendor ' L determir.ed that the generator had not been damaged as a result of this event.
- c. Plant Housekeeping (71707)' !
Storage of material and components, and cleanliness conditions of various areas throughout the facility were observed and no safety arid /or fire hazards were identified. 28 2 --. . .
4 !- d. Clearances (71707) , 3 During this inspection period, the inspectors. reviewed the following ! tagouts(clearancep): : 4
- l-95-009-011 - on EDG IB fuel oil ' transfer pump. The
- inspector found the clearance tag in place and the breaker in j the off position as ruluired.
8 i 2-95-09-002 - control valve V-3661 for SIT. outlet drain valve. 'l to RDT. The inspector found the valve in the closed position
! with fuses removed from RTGB-206.
i
- No deficiencies were . identified.
j e. Technical Specification Compliance (71707) l Licensee compliance with selected TS LCOs was verified. This i j included the review of selected surveillance ~ test results. These i j verifications were accomplished by direct ~ observation of monitoring instrumentation, valve positions, and switch positions, and by a review of completed logs and records. Instrumentation and recorder traces were observed for abnormalities. The licensee's compliance i with LCO action statements was reviewed on selected occurrences as I they happened. The inspectors verified that related plant i
- procedures in use were adequate, complete, and included the most recent revisions. '
4
- f. Effectiveness of Licensee Controls in Identifying, Resolving, and
[ Preventing Problems (40500) l l 1) Licensee Self Assessment The inspector reviewed a special QC assessment of decisions that led to the inadvertent spraydown of Unit I containment. This assessment was requested by the FPL Nuclear Division Vice President and focused on the plant's decision to operate Unit I with FCV 07-1A in the open position and the development and execution of new procedure OP l-0420060, " Venting of Emergency Core Cooling and Containment Spray System." This review found that operating the CS system in an abnormal lineup and executing a new procedure under this condition, coupled with 4 operator error resulted in spraydown of Unit I containment. The assessment also noted that schedule pressure may have prevented timely repair of the CS valve FCV 07-1A. The i inspector noted that the assessment was detailed and provided j
- some recommendations for improvement. l The inspector also noted that the assessment identified that 1 the quarterly surveillance test directed that FCV 07-1A be i lubricated immediately prior to the performance of its i scheduled surveillance. The inspector quest'.sned this 29 l J_ _. . _ - - . . . . . _ . , . _ _ , _ _ _ . _ . . _ _ _ _ _ . . _ _ -.__1
practice since prelubricating the valve prior to performance of the surveillance test would not result in testing the valve's ability to provide the required response time during an actuation. The licensee agreed with this and changed the i procedure to delete the prelubrication under TCN 2-95-177 on l September 7, 1995.
! The inspector also questioned why QA had not documented this deficiency under the STAR program as required by QI 16-PR/PSL-2, Rev 1, "St. Lucie Action Report (STAR) Program." Section 5.1, " Initiation of a -STAR Form." As a result of the question, a 5 TAR was generated on September 6. The failure to document the subject finding via the STAR process is an 3 example of a violation (VIO 335/95-15-01, " Failure to Follow l Procedures," Example 7).
- g. Unit 1 Restart. Activities 1
j The inspector accompanied maintenance QC on a walkdown of the Unit I containment prior to unit restart. This inspection by QC was
- conducted after departmental heads had completed their final inspection, as specified in AP 0010728. It was noted that these department tours had been completed and sigaed off (with a few exceptions for items that would be as a part of unit restart). The l inspector and QC identified approximately ' 40 deficiencies that ;
needed to be corrected prior to unit restart. These included.
= Burned out lights
.
- Missing covers on electrical outlets and components
= Electrical box and panel covers that had not been tightened Areas that needed additional cleaning l .
Some small trash and debris on top of components A scaffold that had not been removed Missing screws and bolts in various components
. Missing condulet covers The inspector noted that the majority of the deficiencies were the responsibility of Electrical Maintenance. A meeting was held with the Maintenance Manager to discuss the items after the inspection was complete. He indicated that these items would be corrected prior to restart and that responsible managers would be counseled on ;
this item. The inspector found that the QC walkdown was very thorough. Discussions with QC found that QC had conducted several inspections prior to this final closeout inspection to verify that containment was being prepared for closeout. IR 94-24 noted that at the
, completion of the Unit I refueling outage in November 1994 the NRC also accompanied QC on the final closeout inspection and identified similar conditions to that found in this inspection. That IR also identified that heavy management reliance was placed on QC to verify the readiness of containment closure. Although containment was 30 h
i returned to a final satisfactory condition it appears that licensee management is employing QC in a line function rather than quality verification role. This item is identified as a management
- weakness.
- 4. Maintenance and Surveillance
- a. Maintenance Observations (62703)
Station maintenance activities involving selected safety-related systems.and components were observed / reviewed to ascertain that they were conducted in accordance with r' equirements. . The following items were considered during this review: LCOs were met; activities were
- accomplished using approved procedures; functional tests and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as 4 required. Work re' quests were reviewed to determine the status of outstanding jobs and to ensure that priority was assigned to safety-related equipment. Portions of the following maintenance activities were observed:
- 1) PWO 61/5k'0 and PWO 61/5571 - Remove PORY 1402 and 1404 from pressurizer, bench test, repair as necessary and reinstall.
1 The valves had been identified as inoperable and the above
- PW0s were generated to remove the valves, determine the cause of failure and correct. The valves were removed and worked using MP l-M-0037, Rev 6, " Power-Operated Relief Valve
, Maintenance." The inspector observed selected portions of the valve disassembly and troubleshooting to determine the cause of failure. These efforts involved several shifts over several ) days. - This work was accomplished in a contaminated work area in Unit 2 RAB. The inspector noted that HP coverage was provided and that a vendor representative assisted maintenance i in this effort. The inspector also noted that continuous supervisory oversight and engineering support were present in
- . the field to provide for a timely repair of these components.
l These items were worked around the clock since they delayed plant restart. The inspector also noted that calibrated tools were being used and that QC provided coverage of this job. The inspector found that work procedures and PWO were in the field and being used. At the completion of the above work, the inspector reviewed the completed work package documentation and found that TC had
'been impicmented for required procedure changes, repair parts, and work was correctly documented, and other support documentation was properly filled out.
31 vs, -
-- w
l Overall, the personnel performing this task were adequately- i qualified and used the appropriate procedures. The overall 1 L work effort resulted in identifying, correcting the problem l and returning the PORVs to service. Adequate supervisory, engineering, and vendor support was provided to successfully
, complete the task in a timely manner. See IR g5-16 for a detailed description of the root cause of the noted PORV j inoperability.
! 2) PWO 1230/65 Perform PCM 11-195 on DG.1A/IB. ! The inspector, while conducting routine- plant inspections, , observed that work on this modification was in progress on DG . i
- 18. Two electricians were completing the work activities t associated with installing new splice boxes for the trip solenoids on the 12 and 16 cylinder engines for DG 18. The inspector reviewed the PWO and procedure that the technicians were using. He noted that the work was nearly complete on the 12 cylinder engine, but only the first few steps of the procedure had been signed off. He questioned the electrician a to what work had been completed and the electrician stated that he had terminated the wiring, torqued the connections, and applied sevepal layers of different types of tape in the sequence indicated by the PC/M. Noting that only a few steps of the PC/M had ueen signed off, the inspector asked specific questions as to the wiring identification, torquing requirements, and sequence and type of tapes used. ,
2 The electrician was unable to locate the guidance provided for wiring identification for correct termination and admitted that, although he had torqued the connection to the correct value, he did not document this in the work package when the step was accomplished. He also stated that he had taken over this job from another individual and had only scanned through the work package instructions and details. Further review of his work activity and the work package by the inspector determined-that the connections had been correctly made and the correct torque value had been used. ~ The circuitry was tested on the night of August 31 and performed satisfactorily. The inspector discussed this ites ; in detail with the Maintenance Manager. and noted that not ' filling out procedural steps as they are accomplished, doing
- only . a cursory review of a work package, and not -being knowledgeable of all aspects of the job can lead to serious :
errors or mistakes in the performance of maintenance ; activities'. The Maintenance Manager stated that he agreed
- with the inspector's observations and that corrective action
- would be taken in this concern.
s ADM-08.02, Rev 7, " Conduct of Maintenance," Appendix 5, Step 5, required. that procedures be present during work and that i 32 4 m
l
,- . . )
)
l l individual steps be initialed once performed. The noted i fallere of the electrician to initial procedural steps on an ;
- as-completed basis is an example of a violation (VIO 335/95- l 15-01, " Failure to Follow Procedures," Example 8). ;
- 3) PWO 95-02-4066 Remove Cylinder Head No. 9. Inspect for Damage.
This PWO was later expanded to perform repairs. The inspector ! conducted periodic inspections of these activities as they ! occurred over a period of approximately one week. Additional details and evaluation of this work is contained in paragraph 3.b.11). I - ha" 4 1 1 4
- I i
1 J e P e 4 9 .} 33 _ . ,m.
M- .b 1 t
.J.
FP&L 6 4 l j predecisional enforcement conference was limited to the immediate procedural
; deficiency. -
t
; Violation C involved the failure to perform adequate inservice testing of the The; inservice testing performed relied solely on the use of. acoustic PORVs
- j. .moniwhg of valve discharge to indicate valve position. This method was not sufficient to discern the difference between bypass flow through the PORV pilot' valves.and. actual changes in main valve position. . At low pressure the inservice .
i test was performed with the block valves open_providing multiple alternative-indications of PORV position. The violation was caused by the reliance on one
, insufficient parameter rather than using diverse indications to determine valve position.-
The NRC relies on implementation of strong maintenance and. testing programs to
- ensure operability'of key, components. The NRC is particularly concerned that 1
'your procedures and controls in diverse parts of the maintenance and testing F . process. failed and led to a common mode failure of the PORVs. In addition,
! ' opportunities to recognize .the inoperability of the valves during a unit trip and during inservice tests were missed. The safety consequences of these multiple' l errors were that the availability of both PORVs for secondary heat removal in a ! post accident condition and for low temperature overpressure protection was lost. The failure to maintain programs that provide defense in. depth to preclude common mode failures is a significant. safety and regulatory concern. Therefore, these violations are classified in the aggregate in accordance with the " General Statement of. Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy), (60 FR 34381; June 30,1995/NUREG-1600) as a Severity Level III problem. In' accordance with the Enforcement Policy, a base civil penalty in the amount of ! $50,-000 is considered for a Severity Level III problem. Because your facility
- has not been the subject of escalated enforcement actions within the last two
. years, the'NRC considered whether credit was warranted for Corrective Action in accordance with the civil penalty assessment provision in Section VI.B.2 of the
- Enforcement Policy. Your immediate corrective. actions included restoring the valves to an operable status, revising maintenance and test procedures, and conducting a comprehensive review of the facts and circumstances which led to the valve failure. Your planned long-term corrective actions included, in part, (1) a phased review of other maintenance and test procedures to ensure quality control attributes are identified and verified.and that post-maintenance and.
inservice testing adequately demonstrate operability; (2) consolidating test groups under a single manager;~and.(3) training on accountability and 4 administration with regard to the control of contractors. Although weaknesses were identified in the root cause analysis for this event, the.NRC determined that. credit was warranted for-the factor of Corrective Action. F In accordance with Section VII.A of the Enforcement Policy, the NRC may exercise i discretion by proposing a civil penalty where application of the factors would 5 otherwise result in a zero civil penalty to ensure that the proposed civil penalty reflects.the significance of the circumstances and conveys the'.
. appropriate regulatory message. The NRC has weighed the circumstances of this case and-finds that it involves a situation where your performance was
- particularly. poor.: ~Specifically, multiple opportunities existed during routine h activities' conducted by diverse groups to recognize the inoperability of the N
/ PROPOSED WWORCMENT ACTION NOT FOR PUSUC DISCLOSURE NTHOUT TIE APPROVAL OF YtB DGECTOR. OE
- ~ ,
A , FP&L 7 h PORVs. Expected provisions to ensure valve operability during maintenance on the PORVs were not implemented. Examples included the failure to include a QC holdpoint for a critical point in the reassembly and the failure to employ independent verification methods when vulnerabilities to common mode failures were introduced by allowing the same individuals to work on the redundant valve. j Management reviews of testing criteria and results were inadequate. Engineering and your plant safety committee accepted post maintenance testing that only verified seat leakage prior to putting the valves back in service. Operations j and Maintenance did not have a common understanding of the scope of the post-maintenance test.ing required. As a result of this misunderstanding, the PORVs ! were placed in the RCS and declared operable without reasonable assurance that the PORVs would perform satisfactorily in the LTOP conditions which would exist prior to performance of the routine surveillance test. The engineering and management reviews of the ability of the acoustic monitors to provide a reliable indication of valve operabilty were inadequate. Your investigation of the event revealed that the PORV pilot valves allowed sufficient bypass flow to actuate the acoustic monitors. A thorough initial review could have identified this testing fl aw. Operator attention to diverse control board indications during testing was I lacking and cnly when the one parameter that was required, i.e., the acoustic monitoring indication, failed, did operators question the other indications they were getting. An adequate post trip data analysis during the July 1995 unit trip should have detected that the PORVs were inoperable. The failure of these diverse methods to ensure system operability and the resulting loss of a safety function required by your Technical Specifications is a significant safety and regulatory concern. Therefore, to emphasize the importance of maintaining adequate and diverse methods to ensure system operability, I have been authorized, after consultation with the Director, Office of Enforcement and the Deputy Executive Director for Nuclear Reactor Regulation, Regional Operations and Research, to issue the enclosed Notice of Violation and Proposed Imposition of Civil Penalty (Notice) in the base amount of $50,000 for the Severity Level III > probl em. You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing you response. In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements. In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter, its enclosure, and your response will be p' laced in the NRC Public Document Room (PDR). To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be placed in the POR without redaction. The responses directed by this letter and the enclosed Notice are not subject to , the clearance procedures of the Office of Management and Budget as required by l the Paperwork Reduction Act of 1980, Pub. L. No. 96.511. Sincerely, l 1 PROPOSED ENFORCEMENT ACTION . NOT FOR PUSLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR OE
b n --oAc O_.mhv 7pr w G:.L[ tbug 6'c-FT NL, kr (o %c M m "DLP (b= C - fLw . ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE-INFORMATION RE0VIRED TO BE AVAILABLE FOR ENFORCEMENT PRE .'3f1 . PREPARED BY: R. L. Prevatte NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This information will be used by EICS to prepare the enforcement letter and Notice, as well as the transmittal memo to the Office of Enforcement explaining and justifying the Region's proposed escalated . enforcement action.) 1. Facility: St. Lucie Unit (s): 1 Docket Nos: 50-355 License Nos: DPR-67 Inspection Dates: Auaust 28 - SeDtember 30. 1994 Lead Inspector: R. L. Prevatte
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is enclosed. [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [X] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2)
VII.D.2
- THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 5
+ 4' I
T- , ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE .
- 4. What is the apparent root cause of the violation or problem?
i The anoarent root causefs) for the event are: e A desire on the cart of the ANPS to chronoloaically tie 1A EDG inoperability to the r,1anae in swina bus power sunolv lintuo made mis was a consorvative decision wit 1 respect earlier in the day. ) to the time a' lotted 9n the anolicab'e 'S AS. I j_ l e A desire by- the licensee to take credit for hourly RC0 control board wal (downs as satisfyina AS (b) of TS 3.1.1.1 and to i represent such actions as havina occurred wit 11n the TS time reouirements.
- An apparent miscommunication between the ANPS and the Operations Supervisor as to how the subject loa entries should be made. l The miscommunication was most probably percentual on the part of the ANPS. The ANPS in ouestion has had disaareements in the cast I with the Operations Supervisor. orior to h's annointment as Operations Supervisor. The insnector witnessed one such !
df13preement f one _ cited by the AN)S in his discussion of this j event as drivtna his actions) durina a Unit 1 startuo. in which ! the ANPS refused to sia1 off a crocedural sten without first < obtainina a Temocrary C lance to correct a misleadina reauirement. I -The Operations Supervisor (then Assistant Operations Supervisor) ; f insisted that the ANP3 sian off the sten. annotatina it with an L explanation of what nortions of the sten did not ano' y to the sianoff. This nethodolcev of dealina with crocedura' prob' ens was ! not an acceptab' e methoc ner olant procedures and recent i manaaemerit direction anc the ANPS held fast to his position. T,hg disaareement crew more intense and the (then) Operations i
! Supervisor and Operations Manaaer were summoned to the control i room to resolve the issue. After a s1 ort review the (then)
Operations Snoervisor directed that t ie crocedure 9n auestion be revised via "emocrary Chanoe. in accordance with otant procedures. l The inspector felt at the time that the ANPS had performed well in , n inaintaining his position and that the (then) Operations Supervisor i
- ind made t ie correct decision with recard to the actions reauired ;
to correct the situation. i 4 .
$ In the current event. the ANPS explained to the inspector that he
- cerceived t'1e (now current) Operations Supervisor as directina him . to modify t ie sub: ect loos. althouah he acknowledaed that no l direct statement to that effect was made. Given :11s cerception. the ANPS stated that he was unwil' ino to ao throuch another , araument with the (current) Operations Supervisor, fearina that it . would. ultimately. affect his Job security. l 1 - TNIS DOCL5eNT CONTAINS PREDECISIONAL INFORMATION - IT CAN NOT BE DISCLOSED OUTSIDE NRC WITNOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR . 6
. Ih a g
ESCALATEp ENFORCEMENT PANEL OUESTIONNAIRE
- 5. State the message that should be given to the licensee (and industry) through this enforcement action.
j.' Control' room loas must provide a chronoloaically accurate description of the actions performed on a aiven shift and must remain inviolate. 1 6. . Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the i facts.and circumstances related to the discovery of the violation? l
. Was it self-disclosing? Was it identified as a result of a generic notification?)
The violation was identified by the resident inspector reviewina l the :icensee's ' oas fo' lowina an EDG' operability issue. I
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference,
- describe preliminary information obtained during the inspection and exit interview.
l The licensee has counseled the individual responsible for the modification of the sub.iect loa entries. The Operations Department issued a N11ht Order reinforcina existina procedure
- ouidance reaardina loa ceeoina. After beina to' d. on Sestember 1.
that the insnector found the loas unsatisfactory (thev 1ad not been corrected to indicate that the Auaust 29 entry was Inisleadin J) . the licensee made a late loa entry correctina the listorical record. What were the immediate corrective actions taken upon discovery of I the violation,. the development and implementation of long-term l corrective action and the. timeliness of corrective actions? i See above. What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis? The licensee has concurred that the modification was not in accordance with site policy. The issue is still emeraina at this time and has not been fully developed by the licensee. I j - TNIS DOCLMENT CONTAINS PREDECISIONAL INFORMATION - IT CAN NOT BE DISCLOSED QUTSIDE Nec WITNOUT THE APPROWAL of THE REGIONAL ADMINISTRATOR 7 l
.( . .
t ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE
- c. LICENSEE PERFORMANCE: This factor takes into account the.last two i years.or the period within the last two. inspections,'whichever is ,
' longer. !
. List past violations that may be related to the current violation (include specific requirement cited and the date issued):
No recent cases of modification of records have been identified. Identify the applicable SALP category, the rating for this category and the overall rating for the last two SALP periods, as l well as any trend indicated: SALP Cateaory: Doerations "he licensm has achieved SALP ratinas of 1 Jr the last two SALP iere have been an increasina nu=her of events periods. associated with Goerations in the cast six mont is: however. these events have not resu' ted in the identification of a ctear trend.
- d. PRIOR' OPPORTUNITY TO IDENTIFY: Were there opportunities for the-licensee to discover the violation sooner such as through normal !
surveillances, audits, QA activities, specific NRC or industry notification, or reports by employees? Licensee manaaemen", could'have. in the cotrse of loa reviews. identified the vio' ation: however. knowlecae of the timina and > oroaression of the 1A EDG operability issue would have been a , crereauisite to such an identification. '
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this inspection? If there were, identify the number of examples and briefly describe each one.
3- There were not multiple examples of this violation identified i durina this inspection period. l
- f. DURATION: How long did the violation exist?
, T11s violation occurred in an isolated fashion. The chances to t ie control room loo were identified anoroximately 2 days after the occurrence. ADDITIONAL COMMENTS / NOTES: B
+
--TN!S 000 MENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITNOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 8 e
, (A a ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE NOTICE OF VIOLATION -
Unit 1 TS 6.8.1.a required that written procedures shall be established and implemented covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A, paragraph 1.h includes administrative procedures for log keeping. St. Lucie Administrative Procedure 0010120, revision 63, " Conduct of Operations," Appendix F, " Log Keeping," stated that log entries were to be made in a chronological order and that, where this was not possible, entries were to be preceded by the words " Late Entry." Contrary to the above, on August 29, 1994, a Unit 1 Assistant Nuclear Plant Supervisor modified and appended Unit I control room log entries made on a previous shift. The modifications were not annotated in any way and created a false impression of the activities of the' previous shift. l l d l l THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION - IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL admit *STRATOR 9 4
( .6 . . ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE During a Unit I control room tour. conducted at approximately 4:00 p.m. August 29, the inspector noted that the LAB 4.16 KV bus was aligned to the IA3 4.16 KV bus and that the IC ICW pump was operating in lieu of the 1A ICW pump. The
' lineup had been made to support maintenance activities in the Unit 1 intake bays. The 2AB bus was normally aligned to the 183 bus and was the source of power for the IC ICW pump. During a postulated LOOP, the IA3 bus would be powered by the 1A EDG. The electrical lineup in question was effected at 1:26 p.m. on August 29.
As documented in IR 94-12, the IC ICW pump had never been tested for load shedding capabilities when powered with the IAB bus aligned to the 1A3 bus. As a result, TS surveillance 4.8.1.1.2.e.3.a and 4.8.1.1.2.e.5.a, which verified load shedding capabilities in response to LOOP and LOOP /SIAS signals, had never been satisfied. As these surveillance tests formed part of the bases for 1A EDG operability, the operability requirement of TS LCO 3.8.1.1 was not satisfied when the 1AB bus was aligned to the IA3 bus with the IC ICW pump operating. During a postulated DBA involving a loss of offsite power, ' the ICW pumps were designed to load shed from their respective busses and. sequence back onto the busses in 9 seconds. The design feature was provided to prevent EDG overload conditions during reenergization of 1E busses. A i failure of an ICW pump to load shed would have the effect of moving the pump from the 9 second to the 0 second EDG load block, increasing the EDGs starting load. The inspector questioned the ANPS as to the operability of the 1A EDG, given that the 1AB bus was aligned to the IA3 bus. The ANPS stated that he was aware that the electrical lineup in question resulted in IC ICW pump inoperability and that the pump had been declared inoperable accordingly. The ANPS stated that the basis for his determination was a Night Order which stated that the pumps powered from the 1AB bus could not be taken credit for when aligned to the 1A3 bus. A caution tag had been hung on a 1A3-to-1AB breaker handswitch to that affect. The inspector raised his concern regarding EDG operability to Operations Department management. After discussions with engineering and other plant personnel, Operations management directed that the 1A EDG be declared inoperable based upon the noted failure to perform required surveillance testing. The 1A EDG was declared inoperable at approximately 5:00 p.m., however the licensee chose to establish the time of inoperability at 1:26 p.m., the time the noted electrical lineup was established. In response to this issue, the licensee performed an evaluation of 1A EDG performance for the subject electrical lineup. As the load shedding capabilities of the IC ICW pump had never been tested, the analysis assumed that the pump would not load shed, effectively moving the pump to the 0 second load block of the 1A EDG. The licensee found that the combination of the 1A HPSI pump (400 HP) and the IC ICW pump (600 HP) alone was enough to exceed the motor starting capability of the EDG, described by Figure 3 of the EDG system DBD as approximately 980 HP.
**TN15 000 MENT CONTAIN$ PREDECISIONAL INFORMATIONa*
AL OF T GIONAL DN ISTRA 10 L_____.-__._._______________________.______.__.__________._
a O m
- 4. i l
4
,V ]
1 ESCALATED ENFORCEMENT PANEL OUESTIONFAIRE 1
! The inspector concluded that, in a Night Order dated by 3,1994, the licensee j failed to accurately convey to operators the findings of IR 94-12, Paragraph .
4.d, which stated,~1n part: l j "On Unit 1, the swing pumps have been normally aligned to the B-train i safety bus...The inspector...found that the same failure to adequately 1
; test load shed capability existed; however, the failure involved not testing the IC ICW and CCW pumps when powered from the Unit 1 A-train
, safety bus. (The failure to properly test the load shedding characteristics of the Unit 2 swing pumps]...resulted in the 2B EDG not being demonstrated operable for the periods in which the C ICW pump was aligned to the B-train safety bus..." In response to this issue, the licensee generated a new Night Order which correctly described the impact of aligning operating 1AB bus pumps to the IA3 j bus. The failure to adequately convey operational limitations to control room
- operators resulted in a recurrence of operating a Unit's electrical plant in a
, configuration for which EDG operability had not been demonstrated. The j licensee's failure to prevent this recurrence is a violation (335/94-20-01). - At approximately 11:00 a.m. on August 31, the inspector reviewed the Unit I control room log and found the following:
- e An entry, made at 1:26 p.m. on August 29, described the change in 4 the electric plant described above. At the end of the
- i. description, the entry stated ".. 1A EDG 005."
e An entry, timed at 2:26 p.m. on August 29, stated "1C AFW Pump . operable, offsite power available, redundant 'B' components operable." < i A.s the 1A EDG was declared inoperable at approximately 5:00 p.m. as a result of the inspectors observations, the inspector questioned control room
- operators about the log entries (the operators questioned had been on watch when the electrical lineup was changed on August 29). The operators had no knowledge of the log entries detailed above. The inspectors discussed the issue with the Operations Supervisor, who stated that the entries were most probably made by the peak shift ANPS on August 29 to reflect the fact that the EDG was declared inoperable. The Operations Supervisor also stated
e The time of EDG inoperability had been declared to be the time when .the 1AB bus was aligned to the 1A3 bus (1:26 p.m. on August 29). e The entry describing the availability of offsite power supplies and the operability the IC AFW pump and B side ECCS components had TNis DOCUMENT CONTA!NS PREDECISIONAL INFORMATION
- IT CAN NOT BE 0!$ CLOSED OUTSIDE NRC WITNCUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 11
jr f3 s . 2 i i l ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE been made to satisfy AS (b) of TS LC0_3.8.1.1, which required such checks when an EDG was declared inoperable. The entry was said to take credit for normal _ control room walkdowns.and log entries in the RCO, control room and out-of-service i vg. o The method of log entries in this case was not in accordance with site procedures.
.The inspector discussed the matter with the ANPS who had been on duty during the peak shift on August 29. The ANPS stated that he did make the log entries in question and'that the entries were the result of a discussion with the l Operations' Supervisor, who had directed the ANPS to make log entries describing inoperability of the 1A EDG. . The ANPS stated that his
- understanding of the Operations Supervisor's directions was that the logs from the day shift of August 29 should be augmented to include the EDG
> inoperability. The ANPS stated that, in the course of the discussion, he informed the Operations Supervisor that, if inoperability was taken from 1:26
- p.m.. then the one . hour period for completion of AS. (b) of TS LCO 3.8.1.1 had been exceeded. The ANPS stated that the Operations Supervisor directed that RCO board walkdowns and various control room logs be taken credit for as satisfying the AS, a practice which had been used in the past under similar circumstances. Finally, the ANPS stated that he had made the noted log
- entries with hesitation, but believing that the actions were made under the direction of the Operations Supervisor.
The Operations Supervisor acknowledged the discussion, stating that he had directed the ANPS to declare the 1A EDG inoperable effective at 1:26 p.m. on August 29. The Operations Supervisor stated that it was not his intent that the previous shift's logs be altered and that an apparent miscommunication had i existed between himself and the ANPS. The inspector reviewed the Bases for TS LC0 3.8.1.1 which, with regard to the verification of offsite power and component operability required in AS (b) of the LCO, stated:
"The term verify as used in this context means to administratively check by examining logs or other information to determine if certain components are out-of-service for maintenance or other reasons. It does not mean to perform the surveillance requirements needed to demonstrate the OPERABILITY of the component."
Consequently, the inspector found that the methodology employed for making the 2:26 p.m. log entry of August 29 was in keeping with the TS. However, the
- inspector found-that the time logged for the activity was misleading both in the statement of when the activity occurred and by whom the activity was performed.
e 1
--THIS DOCLMENT CONTAINS PREDECISIONAL INFORMATION**
IT CAN NOT BE DISCLOSED OUT51DE NRC WITHOUT THE APPROWAL OF THE REGIONAL ADMINISTRATOR 12 f T. - - _ - _ - - . . - > ~ . . . . _ _ _ _ ~
__ _ _ . . _ . . - ~ __ . _ _ _ _ _ . _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ .
;' ' ( .6 . ?
ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE Therefore, the inspector concluded that : e The portion of the August 291:26 p.m. log entry stating that the 1A EDG was DOS, was misleading in that the EDG was declared 005 at, approximately 5:00 p.m. that day. Further, the entry did not reflect the activities of the day shift operators. e The August 29 log entry of 2:26 p.m., stating that offsite power ' sources were available and that the IC AFW pump and redundant B side components were operable, was misleading in'that the subject verifications were~not performed on that shift. In response to this event, the licensee issued a Night Order on August 31 reiterating procedural-requirements for maintaining logs chronologically. The inspector reviewed Administrative Procedure 0010120, Revision 63, " Conduct , o f Operations," and found that Appendix F covered log keeping. Section 2 of ' the appendix stated, in part, "... entries are to be made in chronological order. Where this is NOT possible, entries shall be preceded by the words Late Entry." The ANPS's actions, relative to the modification of the logs of i the previous shift were counter to the requirements in the procedure and, as such, constitute a violation (VIO 335/94-20-02). 1 l e ) 1 4 4 h l' TNIS DOCLMENT CONTAINS PREDECISIONAL INFORMATION - IT CAN NOT BE DISCLOSED OUTSIDE NRC WITNOUT THE APPROWAL OF THE REGIONAL ADMINISTRATOR 13
l ' - bb = , - 1 l 1 I (l l J i ESCALATION AND M1TIGATION FACTORS (57 FR 5791, Fetiruary 18, 1992) l I I Ig M IFICATim II M ECTIVE LICENEE PRIS IRA.TIPLE , gWAT!W ACTitM PgEFINIAECE (FFERilEITY TO nemessurse IgENTIFY
+/- 50E +/- 50K +/ 1005 + 100E + 1001 ~+ 1005 3
i ,
. 1 Licensee Timeliness of Current Licensee should Multiple used for '
identified (M) corrective violation is an have identified examples of significant I (To be applied action (M) isolated vlotation violation regulatory l oven if Ipid NRC have failure that is sooner as a . Identified message to ?- licensee could to intervene to inconsistent result of prior during- ticensee. (E) have . eccesplish with licensee's opportunities inopoetion identified the satisfactory good such as audits (only for SL I, vlotation short term or performance (M) (E) II or !!! l sooner) remedial actton violations) (E) ; (E)] 4 NRC identified Promptly. Violation is opportmities s OT MR CONSIDERATIQRS' ' (E) developed reflective of eveltable to . . ; .. .. ..
. ....e ..
i schedule tor ticonsee's poor discover A Lesel-aspects'and potenttalc tons term or doctining vlotation such 'lltigetfort risks ' f1 i corrective performance (E) as through . . . . < .3- ~ W action (M) prior 2.' : Negligence,' careless die.a notification- Lregard,; willfulness andl . + . (E) management' involvement E as Self- Degree of Prior Esse of earlier 3.; Economic,'persone'[ l ore i disclosing licensee performance and discovery (E) . corporate gain (M 25% if initiative (M) effectiveness L. ; there was (To devotop of previous 4: Any otherrregulatory- framet 1 initiative to corrective corrective ; work factors that need to be~ identify root actions and action for ' considered pending actione cause) root causel simiter with regard to ticonsing,s. 4 vlotationo _ comunission meetingf or prese = l conference. : !
- Licensee Adequecy of the SALP - Period of time . . , . ,,...f.. . . -
identified as root cause considers between 5; ; Whet fs'the intended message i a result of analysis for SALP 1 - (M) vlotetton and ' for the licensee arr$ the - ' generic the violation SALP 2 - (0) notification indastry?: notification received ty (M) SALP 3 - (E) (M) Licensee (E) .......J.K.' NOTES-+-aa*I-2 Comprehensive Prior simiterity ,
, corrective enforcement between the l action to history vlotation and prevent including notification .
occurrence of escalated and (E) , similar non-escalated ' violation (M) enforcesant Imendiate Level of corrective 4 management ;
. action not review the taken to notification restore safety received (E) and compliance (E) mm SAFETY SIGNIFICANCE: In determining the safety significance of a violation in conj metion with the enforcement process, the evetustion should consider the technical safety significance of the vlotation as well as the regulatory significance. Consideration should be given to the matter as a whole in light of the ciressestances surrounding the vlotation. There may be cases in which the technical safety significance of the metter is low while the process control failure (s) may be significant, and, therefore, the severity level determination should be based more on the process control f ailure(s) then
, on the technical safety issue. The following factors should also be considered: 1) Did the violation
- actually or potentially tapect pubtle health and safety? 2) What was the root cause of the vlotation?
- 3) Is the violation an isolated incident or is it Indicative of a programmatic breakdown? 4) Wes s a- .t swore of or involved in the vlotation? 5) Did the violation involve wittfulness?
I A
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! ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 63
- ; CONDUCT OF OPERATIONS APPENDIX F l LQG KEEPING l (Page 1 of 4).
1.. 2303m[: A. Chronological watch station' log entries shall be made in black ink or other l . permanent recording method. Log sheet and check sheet entries shall be i made in black ink. ) B. There shaJI be no erasures, ilquid paper, correction tape,' highliters or other methods of obilteration. Errors shall be lined through to indicate a deletion, but the deletion entry shall be legible.- l C. The operator making the deletion shall initial along side it and enter the correct Information. Log entries shall be concise and definitive. I
- 2. Chronoloaical Loos:
A. Log books shall be maintained at the RCO, NO/SNPO, NTO/NPO and ANPO normal stations. Entries are to be in black ink and concise and complete l enough tol reconstruct the events of the shift. Particular attention should be made to the entries pertaining to any abnormal condition that occurs. The entries aro to be made in chronological order. Where this is NOT possible, entries shall be preceded by the words Late Entry. The following entries are recommerded:
- 1. Entries in the RCO log should inhude, but are NOT to be limited to, the follovdng:
- a. Conditions at the beginning of each watch.
- b. Significant changes in plant conditions.
- c. Any new condition that would limit unit generation.
- d. Special tests, as well as principle periodic and surveillance tests.
- e. Control problems associated with major equipment or systems.
- f. Peactor trips and reason, when known.
l g. Automatic protective action (e.g., SIAS, CIS, MSIS).
~_
4-y 01-15-97 08:05a Directory H:\1960 PEN.ENF\96464STL.DIR\*.*
- Frco: 15,187,968 i
.- - Current- <Dir> .. Parent <Dir>
I: 'EAW . 52,151 11-08-96 08:26a s NOV .REV 11,594 11-13-96'12:39a REPORT . 75,626 11-26-96 04:46p 1 k d s e 9 d f l9 g)h
ENFORCEMENT ACTION WORKSHEET BREAKDOWN IN MANAGEMENT CONTROL OF THE ST. LUCIE EMERGENCY PREPAREDNESS PROGRAM PREPARED BY: James L. Kreh DATE: Noveinber 7.1996 This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. Signature Facility: St. Lucie Plant Units: 1&2 Docket Nos.: 50 335, 50 389 License Nos.: DPR 67, NPF 16 Inspection Report No.: 96 18 Inspection Dates: October 7 18 and October 28 November 1, 1996 Lead Inspector: J. L. Kreh
- 1. Brief Summary of Inspection Findings:
Violation A On the evening of October 3. 1996, the licensee conducted a test of its automated system known as the FPL Emergency Recall System (informa.lly called " autodialer") for notifying the emergency response organization (ERO) in the event of an off-hour emergency requiring augmentation of the on-shift crew for staffing and activation of emergency response facilities (viz., Technical Support Center [TSC]. Operational Su] port Center [0SC]. and Emergency Operations Facility [ EOF]). The autodia'er did not operate, and no individuals received notifications during the test. A failure assessment by the licensee disclosed that the autodialer had been in an i inoperable configuration for a period which apparently began on July 22. 1996. In addif N, ihe inspection identified the licensee's failure to adequately maii w o manual backup system (a " call tree") for ERO call-out over an indetoMNte period (at least the last several years). These concurrent deficiendes represent a failure (during the period July 22-October 3.1996 at minimum) to maintain the capability to execute the provisions of the REP and its implementing procedures in a timely manner with respect to mobilization of the ERO during off-hours. PREDECISIONAL ENFORCEENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR OE
i - ENFORCEMENT ACTION 2-WORKSHEET Violation B The licensee's training program for ERO personnel has not been adequately I implemented since at least 1994. This violation includes failure to provide opportunities for most personnel to participate in exercises and/or drills, failure to provide annual retraining to certain designated aersonnel in 1994 and 1995, failure to provide any training for certain ERO positions with respect to selected implementing procedures, and failure to remove individuals from the ERO roster when their respirator qualifications had lapsed.
- 2. Analysis of Root Cause:
The root cause of both violations is failure of licensee management to (a) provide an appropriate level of oversight of the emergency preparedness program as required by the REP, and (b) ensu'e the implementation of timely and effective corrective actions for identified findings and deficiencies in emergency preparedness.
- 3. Basis for Severity Level (Safety Significance):
For both violations- Sucolement VIII - Emeraency Preoaredness. SL III Section C.3 of Supplement VIII presents as an example, " Violations involving . . . a breakdown in the control of licensed activities involving
- a number of violations that are related ... that collectively represent a
! potentially significant lack of attention or carelessness toward licensed responsibilities." l Section IV.A of the Enforcement Policy states that "a group of Severity Level IV violations may be evaluated in the aggregate and assigned a single, increased severity level, thereby resulting in a Severity l Level III problem, if the violations have the same underlying cause or programmatic deficiencies, or the violations contributed to or were unavoidable consequences of the underlying problem."
- 4. Identify All Previous Escalated Actions Within 2 Years or 2 Inspections
> 95-180: PORVs Inoperable Due To Personnel Error: SL III l
> 96-040: Dilution Event: SL III
> 96-249: Multiple Examples of Inadequate 50.59 Reviews: SL III
- 5. Identification Credit? Yes Violation A Date licensee was aware of issues requiring corrective action:
l October 3. 1996. This identification credit /date applies only to the autodialer inoperability portion of the violation. The problem with the manual call-out system was NRC/CI-identified. PREDECIsIONAL ENFORCEENT INFORMATION NOT FnR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR OE
o ENFORCEMENT ACTION
- WORKSHEET
]
1 Explain application of identified credit, who and how identified and considerat1on of missed opportunities: - The-inoperability of the autodialer was identified by the licensee on 10/3/96, but could have been identified much earlier if periodic ; functional tests (e.g., . weekly) had been performed. - With appropriate administrative controls in place (as had been recommended by an 'EP Coordinator as early as April 1996), autodialer inoperability would have almostcertainlyhavebeenprecluded. An autodialer problem (limited in scope--not a complete syst.em failure) also occurred during the NRC-evaluated June 1993 exercise, but corrective action for that problem was . clearly not sufficiently comprehensive. . Violation B Date when the licensee was aware of issues requiring corrective action: January 1996. Explain application of identification credit, who and how identified and consideration of missed opportunities: Many of the identified failures in the licensees training program were self-identified in a self-assessment that was performed in Januar) 1996. However, some of the identified failures were not self-identified, but should,have been through existing licensee program controls.
- 6. Corrective Action Credit? No Violation A Administrative controls have been implemented for the autodialer under Protective Services Department Guideline .No. PSG-015. " Maintenance and Testing of the Emergency Recall System"~ Revision 0, dated 10/29/96. For the manual call .out system, individuals required to maintain a copy of the procedure were added to the controlled distribution list, and a drill was conducted on October 10, 1996 with reasonably successful results.
Application of corrective action credit: (1) No credit for autodialer issue because identified by licensee EP Coordinator in early 1996 and no action taken: (2) Credit for correction of manual call-out problem after identification to licensee on 10/7/96. Violation B
. t The licensee has initiated action items to evaluate and determine corrective actions for self-identified issues. The licensee is currently completing a mass training effort for all emergency response organization positions necessitated by recent changes in responsibilities from Corporate staff assignments to Plant staff assignments.
4 Application of corrective action credit: No credit because the licensee ' has not yet fully determined or implemented programmatic changes to resolve identified issues. PREDEC!sIONAL ENFORCEENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
ENFORCEMEMT ACTION 4-WORKSHEET
- 7. Candidate For Discretion? No Licensee's performance in emergency preparedness is now recognized to have been particularly poor during the past several years.
- 8. Is A Predecisional Enforcement Conference Necessary? Yes Why? To determine whether the subject violations represent a programmatic breakdown in emergency preparedness.
If yes. should OE or 0GC attend? Yes Should conference be closed? No
- 9. Non Routine Issues / Additional Information:
0THER FINDINGS FROM THE OCTOBER 1996 EP PROGRAM INSPECTION Violation Failure to establish an Emergency Plan Implementing Procedure (EPIP), or to have an adequate EPIP. with appropriate implementing details to address certain aspects of the Radiological Emergency Plan as follows: a, the transfer of OSC functions to an alternate location in the event that evacuation of the primary OSC is required (EPIP-3100032E. "On-site Support Centers", contains no implementing details for the statement in Radiological Emergency Plan Section 2.4.4 that "In the event that the OSC becomes untenable, the Emergency Coordinator will designateanalternatelocation."){inadequateprocedure}.and
- b. recovery activities upon reaching a stable )lant condition following
( an emerg ncy (Radiological Emergency Plan Section 5.4) (no procedure . Emeroency Preoaredness Proaram Weaknesses
- 1. Inadequate program of drills to ensure availability of sufficient ERO personnel and timeliness of ERF staffing -
- 2. Management failure to ensure the implementation of timely corrective actions for certain emergency preparedness deficiericies and weaknesses. Examples are:
- a. failure to address concerns regarding the audibility of the Gaitronics (or plant public-address system) formally identified in late 1994 and still being tracked as an open item by the licensee's corrective action system,
- b. failure to provide adequate corrective action to address a questionable capability for notification of the State of Florida within 15 minutes of an emergency declaration (identified by an NRC inspection in February 1995), and PREDECIsIONAL ENFORCEEKT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR OE
ENFORCEMENT ACTION , WORKSHEET . t
- c. failure to implement timely corrective actions for i deficiencies and recommer.dations identified by the critique of the Hurricane Erin response in August 1995 (examples of issues: identify hurricane-safe structures onsite and a plan for positioning personnel in those structures: designate an onsite individual to monitor the hurricane path; establish consistent staffing policies) ,
- 10. This Action is Consistent With the Following Action ('or Enforcement Guidance) Previously Issued: .
Supplement VIII, Section C.3-t i O k PREDECISIONAL ENFORCEENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
ENFORCEMENT ACTION- 6-WORKSHEET
- 11. Regulatory Message:
Management must provide strong and consistent oversight and support for emergency preparedness activities in order to ensure a viable emergency response capability at all times.
- 12. Recommended Enforcement Action:
.Two SL IV violations evaluated in the aggregate as a SL III problem
- 13. Should This Action Be Sent to OE For Full Review? No
- 14. Exempt from Timeliness: No Basis for Exemption: N/A Enforcement Coordinator: '
DATE: i l l l t PREDECISIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR. OE-
F i ENFORCEMENT ACTION 7- ' WORKSHEET DRAFT NOTICE OF VIOLATION St. Lucie Plant Inspection Report Nos. 50-335. 50-389/96--18 A. 10 CFR 50.54(q) requires that nuclear power plant licensees follow and maintain in effect emergency plans which meet the planning standards of 10 CFR 50.47(b) and the requirements in Appendix E to 10 CFR Part 50. Section 2.4 of the licensee's Radiological Emergency Plan (REP). Revision 31, states that activation of the Technical Support Center (TSC) and the Operational Support Center (0SC) will be initiated by the Emergency Coordinator in the event of an Alert. Site Area Emergency, or General Emergency, and that arrangements have been made to staff the TSC and OSC in a timely manner. Also specified is that activation of the Emergency Operations Facility (E0F) is required for a Site Area Emergency or General Emergency, and that arrangements have been made to activate the EOF in a timely manner. The REP requirements delineated above are implemented by procedure EPIP-3100023E. "On-Site Emergency Organization and Call Directory". Revision 72. The instruction in Section 8.2 of that procedure states that, upon the declaration of an emergency classification. "the Duty Call Supervisor will initiate staff augmentation" using the " Emergency Recall System or Appendix A. Duty Call Supervisor Call Directory to notify persons..." Contrary to the above, from approximately July 22 to October 3,1996, arrangements were not available to staff or activate the TSC OSC or EOF in a timely manner because the licensee did not have the capability to implement either the primary method (using the Emergency Recall System) or the backup method (using the Duty Call Supervisor Call Directory) for notifying its )ersonnel to report to the plant during off-hours to staff and activate t1e TSC. OSC, and EOF. B. 10 CFR 50.54(q) requires that nuclear power plant licensees follow and maintain in effect emergency plans which meet the planning standards of 10 CFR 50.47(b) and the requirements in Appendix E to 10 CFR Part 50. REP Section 7.2.2. " Training of On-Site Emergency Response Organization Personnel", states, "The training program for members of the on-site emergency response organization will include practical drills as appropriate and participation in exercises, in which each individual demonstrates an ability to perform assigned emergency functions." The licensee's Plan further states "For employees with specific assignments or authorities as members of emergency teams. initial training and annual retraining programs will be provided. Training must be current to be maintained on the site Emergency Team Roster." Contrary to the above the licensee failed to provide a program which included an opportunity for each individual assigned to the on-site emergency response organization to participate in a drill or exercise, as follows: PREDECIsIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR OE
4 , ENFORCEMENT ACTION 8-WORKSHEET
- 1. In 1994, the licensee failed to provide training for 17 positions (approximately 92 individuals) identified as part of the on-site response organization. In 1995. the licensee failed to provide training for 8 positions (approximately 54 individuals) identified as part of the on-site response organization.
- 2. The licensee's training program failed to include initial, periodic l retraining, or information on revisions with respect to certain '
procedures required to be implemented by several identified i positions. These procedures included EPIP 3100026E, Criteria for Conduct of Evacuation: EPIP 3100027E. Re-entry: and EPIP 3100035E, ) Offsite Radiological Monitoring.
- 3. For the calendar year 1995. the licensee failed to remove from the emergency response organization 4 individuals who had not completed retraining as required, and their training qualifications had expire in 1994. The licensee failed to remove 6 individuals from the emergency response organization effective October 6, 1996, who had not remained qualified to fill response team requirements as a result of allowing their respirator qualifications to lapse.
l l I PREDECIsIONAL ENFORCEMENT INFORMATION - NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
i s 1 I l
+
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. Current .<Dir>- .. Parent <Dir>
CHRON- . 5,283 11-02-96 01:19a EAW . ,50,291 11-01-96 08:31p - REPORT- . 59,927 11.19-96 03:18p t 4 4 4 . 4 1 1 i i 4 I ! I r
. t I t 4
r I
g ENFORCEMENT ACTION WORKSHEET INFORMATION RE0VIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL ST. LUCIE UNAUTHORIZED ACCESS PREPARED BY: Lori Stratton DATE: 10/30/96 NOTE: The Section Chief of the responsiole Division is responsible for pre)aration of this questionn 4re and its distribution to attendees prior to an Enforcement Panel. The Sec. ion Chief shall also be responsible for providing the meeting location and tele) hone bridge number to attendees v'ia e-mail [ENF.GRP. CFE. OEMAIL JXL. JRG. SiL. LFD appropriate RII DRP. DRS: appropriate NRR. NMSS). A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is required. Copies of applicable Technical Specifications or license conditions cited in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed. This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. , Signature
- 1. Facility: St. Lucie Unit (s): 1 and 2 Docket Nos: 50-335. 50-389 License Nos: DPR-67. NPF-16 Inspection Report No: 96-19 <
Inspection Dates: 10/21 - 10/25/98 Lead Inspector: L. Stratton
- 1. Brief Summary of Inspection Findings:
A. 10 CFR 73.55(7) requires that licensee's shall establish an access authorization system to limit unescorted access to vital areas during non-emergency conditions to individuals who require access in order to perform their duties. l The licensee's Physical Security Plan (PSP). Revision 48. dated 2/23/96 states. "Only those individuals with identified need for access and having appropriate authorization. shall be granted j unescorted Vital Area access." j Contrary to the above, from July 28, 1996 to September 19. 1996 an individual whose employment terminated on July 28. 1996, had unescorted access to protected and vital areas without appropriate authorization. In addition on August 7: August 9: and August 15. 1996, that individual entered the protected area and had access to vital areas. PREDECISIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIc RELEASE W/0 APPROVAL OF DIRECTOR. OE
4 4-ENFORCEMENT ACTION 2-WORKSHEET-Also, three other individuals had unescorted access to the protected and vital areas after they were terminated from the period of July 27 to September 19, 1996, without appropriate authorization. However, those individuals did not access the-protected or vital _ areas. B. 10 CFR 73. Appendix G, states that an actual entry of an unauthorized person into a protected area or vital area be reported within one hour of discovery. 4 2 10'CFR 73. Appendix G, states that any failure, degradation, or discovered vulnerability in a safeguards system that could have allowed unauthorized or undetected access to a-protected area or a vital area had compensatory measures not been established, be recorded within 24 hours of discovery in the safeguards event 109 Contrary to the above, on October 9, 1996, the licensee discovered : that an individual had been terminated on July 28, 1996, and had
. entered the protected area on five different occasions, yet failed to make a report within the one hour timeframe. In addition, on September 19, 1996, the licensee discovered three individuals who had pu,n.usly been terminated on July 27 July 28. and August 24, 1996 that had access to the protected area and failed to report that discovery in the safeguards event log.
- 2. Analysis of Root Cause
- )
Violation A: Responsible organizations failure to adhere to Administrative Procedure (AP) 0010509, " Personnel and Material' Control," Revision 18, dated 9/30/96 and notify security when individuals were terminated. Also, those organizations' inadequate review of the 31 day vital area access i lists. Violation B: i Security's failure to implement Security Procedure (SP) 0006125, " Report ! of Safeguards Events," Revision 10 dated 10/9/96. j
- 3. Basis for Severity Level (Safety Significance): [ Include example from the supplements, aggregation, repetitiveness, willfulness, etc.]
Violation A: Supplement III. SL III The NRC Enforcement Policy states as example, "A failure or inability to control access through established systems or procedures, such that an unauthorized individual (i.e., not authorized unescorted access to the protected area) could easily gain undetected access into a vital area from outside the protected area," PREDECISIONAL ENFORCEENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL of DIRECTOR, OE
9
)
l . ENFORCEMENT ACTION- ' WORKSHEET l Violation 8: Supplement III SL III The NRC Enforcement Policy states in Section 7.10. "The severity level assigned to the licensee's failure to submit a required, acceptable, and timely report on a violation that occurred at the licensee's facility is-normally the same as would be assigned to the violation that should havs been reported. However, the severity level for submitting a late report may be reduced, depending on the individual circumstances. NOTE: This is a first repeat of this violation with respect to failure to make a one hour report. 4 Identify Previous Escalated Action Within 2 Years or 2 Inspections? [by EA#, Supplement, and Identification date.] 95-180: PORVs Inoperable Due To Personnel Error, SL III 96-040; Dilution Event: SL III 96-249: Multiple Examples of Inadequate 50.59 Reviews: SL III
- 5. Identification Credit? [ Enter Yes or No): No Consider following and discuss if applicable below:
o Licensee-identified a Revealed through event a NRC-identified a Mixed identification a Missed opportunities
, . Violation A:
Security immediately removed the individuals' access when discovered. However, The licensee missed an opportunity to evaluate their access program on 8/19/96, when Condition Report (CR) 96-2041 was issued. This CR identified that an individual wds presented a FPL severance package and his access was still valid 12 days later. In addition, although Security did remove the individuals' access authorization, they missed an op)ortunity to validate that those individuals did not use their unautlorized access from the date of their respective terminations. Violation B: Several ec'ssed op)ortunities with respect to reportability occurred at St. Lucie. (a) T1e security access coordinator on September 19 failed to notify any other personnel when he discovered three individuals had unauthorized access. Therefore. the event was not logged in the safeguards event log. (b) When the security access coordinator learned on October 9 that one of the individuals he had earlier identified as having unauthorized access actually entered the protected area, he did notify his supervisor. However, the event was neither one hour reported nor logged in the safeguard event log. (3) When the Security Manager learned of the event of October 11. a determination was made to put the event in the safeguards event log rather than make a one hour report. . The event was eventually reported on October 16. PREDECIsIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR OE
l l , 1 ENFORCEMENT-ACTION 4- 1 WORKSHEET A possibility exists that if the individual did not apply for a position at Turkey Point and had his processing for that position conducted by i the St. Lucie staff for convenience purposes, the problem would not have i been identified. (See attached chronology for more specific details). Enter date Licensee was aware of issues requiring corrective action: - Violations A and B: September 19. 1996
- 6. Corrective Action Credit? [ Enter Yes or No): No.
Brief summary of corrective actions: Violation A:
- Security immediately removed the individuals' unescorted access to the protected and vital areas.
- FP&L inter-office correspondence dated October 25 to all responsible organizations that by COB 10/30/96. an access review and certification that all individuals listed on the attached
. access lists are valid.
- A comparison of a listing of 594 terminated individuals to the security computer to verify that unescorted access was correct, which was started October 17 and completed October 31. Out of those 594, three more individuals were identified. Two individuals were identified for Turkey Point and one individual was identified with unauthorized access to both facilities.
- However, an inadequate assessment of CR 96-2041 which resulted in no specific corrective action could have identified to the licensee a problem existed as early as 8/19/96. Also, again on 9/19/96, when the access coordinator discovered the three individuals who had unauthorized access. Finally on October 9 when the licensee discovered an individual had entered the 3rotected area after termination, the licensee once again should lave identified a problem existed with respect to terminations and unescorted access. Not until the period of October 16, when the event was called to the NRC to October 25, when CR 96-2496 was generated, did the licensee recognize a significant problem existed.
Violation B:
- Tne licensee did eventually determine a one hour report was warranted. ,
No other corrective action had been initiated. The corrective i action generated by the violation cited in IR 96-16 was partially complete when the events occurred and fully completed prior to the 1 PREDECIsIONAL ENFORCEENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR OE
s L .. .. ; p- r -1 i ! ENFORCEMENT ACTION 5-WORKSHEET-finishLof the inspection. However, the corrective action for IR' 96-16 was to change the procedure to include tampering events. ; whereas the cause of these violations was adherence to the procedure itself. .,
- 7. Candidate For ;:3cretion?<[See attached list] _ [ Enter Yes or No]: -]
Indeterminate. The licensee's failure to report the event within one hour is a , repeat violation, 8.. Is A Predecisional Enforcement Conference Necessary? , [ Enter Yes or No]: Yes. ! Why: -To facilitate a better understanding of root'cause and missed l opportunities. If yes, should OE or OGC attend? [ Enter Yes or No]: Yes ' Should conference be closed? [ Enter Yes o'r'No]: No l
- 9. Non Routine Issues / Additional Information:
See attached chronology. i
- 10. This Action is Consistent With the Following Action (or Enforcement j Guidance) Previously Issued: [EICS to provide] [If inconsistent. ;
include:] Basis for Inconsistency With Previously Issued Actions (Guidance) {
- 11. Regulatory Message: Encouragement of prompt identification and prompt comprehensive corrective action.
- 12. Recommended Enforcement Action:
Severity Level III and Severity Level IV violation.
- 13. This Case Meets the Criteria for a Delegated Case. [EICS - Enter Yes or No]'
No , l
- 14. Should This Action Be Sent to OE For Full Review? [EICS - Enter Yes or l
No] , No . I If yes why:
'PREDECISIONAL ENFORCEENT INFORMATION . NOT FOR PUBLIC RELEASE WO APPROVAL OF DIRECTOR. OE -
l i
. ENFORCEMENT ACTION 6-WORKSHEET j
- 15. Regional Counsel Review [EICS] At the panel. ;
No Legal Objection Dated i
- 16. Exempt from Timeliness: [EICS] No. '
Basis for Exemption: Enforcement Coordinator: DATE: I l I i I PREDECISIONAL ENFORCEENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR. OE
ENFORCEMENT ACTION. - WORKSHEET ISSUES TO CONSIDER FOR DISCRETION a Problems categorized at Severity Level I or II. i o Case involves overexposure dr release of radiological material in. excess l of NRC requirements. , a Case involves particularly poor licensee performance. O Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with 01 regarding the case, whether or not the matter has been formally referred to 01, and whether or not OI intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or , management involvement should also be included. O Current violation is directly repetitive of an earlier violation, o Excessive duration of a problem.resulted in a substantial increase in I risk. a Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit a Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) a Licensee *s sustained performance has been particularly good, o Discretion should be exercised by escalating or mitigating to ensure , that the proposed civil penalty reflects the NRC's concern regarding the ' violation at issue and that it conveys the appropriate message to the licensee. Explain, i l 1 1 1 PREDECIsIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR OE l
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9516 .RPT 73,983 10-27-95 12:23p ATTENDEE. 67,568 10-11-95 04:22p BRIEF . MAT 109,566 09-22-95 03 :04p CHRON .REV 2,737 11-02-95 09:31a DISCERTI.BF1 12,906 11-01-95 09:06a DISCRETI.BRF 39,355 10-27-95 02:43p EAWPOST .PEC- 72,473 10-11-95 05:24p EAWPRE .PEC 74,475 09-28-95 01:23p EN . 4,786 11-15-95 01:17p FINALSIG.SDE 31,541 11-14-95 08:42a LTRTOOE .REV 43,667 11-03-95 04:05p OECMMTS . 24,084 10-27-95 01:03p OECMMTS .112 27,083 11-03-95 11:01a OECMMTS .117 25,312 11-07-95 02:25p PKGREV . 12,527 11-02-95 11:43a QUEST . 43,077 09-05-95 02:36p REFLIST . 0 10-16-95 03:43o REFPKG .CVR 0 10-16-95 03:34p l i A Y
,f 1
HEFERENCE DOCUMENT CHECKLIST
, REGION 11 ENFORCEMENT AND INVESTIGATIONS COORDINATION STAFF j ENCLOSURES j~ EA 95-180 -
FLORIDA POWER AND LIGHT COMPANY
; ST. LUCIE NUCLEAR PLANT ,
[1] NRC inspection Reports and other documentation of the case:
- e. NRC inspection Report 50-335/95-16 AND 50-389/95-16 I .(2) Licensee reports (Submitted at the Conference):
- a. Engineering Evaluation - Evaluation of PORV Unavailability on Plant Operations I
- b. LER 95-238, PORVs inoperable Due to Personnel Error, ;
i August 22,1995 :
- c. Topical Quality Assurance Report .;
1 l l [3] Applicable license conditions: l Technical Specification 3.4.13 Technical Specification 4.0.5 : i- Article IWV-3000, Test Requirements [4] Applicable licensee procedures or extracts
- a. General Maintenance Procedure No.1-M 0037
- b. Second Ten Year Inservice inspection interval inservice Testing i Program
[) Copy of discrepant licensee documentation referred to in citations such as 1 . NCR, inspection record, or test results
- [5] Enforcement Panel Questionnaire /PEC Briefing Paper
[6] Licensee PEC Presentation Materials
!; Referenced ORDERS or Confirmation of Action Letters (CALs) i i
[] Other miscellaneous documents: i ENFORCEMENT COORDINATOR: LINDA WATSON (404) 331-4192 1 t l
4 I e 01-08-97 05:33p Directory H:\1950 PEN.ENF\95180STL.DIR\*.* Froo: 5,259,264
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9516 .RPT 73,983 10-27-95 12:23p ATTENDEE. 67,568 10-11-95 04:22p BRIEF . MAT 109,566 09-22-95 03 :04p CHRON .REV 2,737 11-02-95 09:31a DISCERTI.BF1 12,906 11-01-95 09:06a DISCRETI.BRF 39,355 10-27-95 02:43p EAWPOST .PEC 72,473 10-11-95 05:24p EAWPRE .PEC 74,475 09-28-95 01:23p l EN . 4,786 11-15-95 01:17p FINALSIG.SDE 31,541 11-14-95 08:42a LTRTOOE .REV 43,667 11-03-95 04:05p OECMMTS . 24,084 10-27-95 01:03p OECMMTS .112 27,083 11-03-95 11:01a OECMMTS .117 25,312 11-07-95 02:25p PKGREV . 12,527 11-02-95 11:43a QUEST . 43,077 09-05-95 02 36p REFLIST . 0 10-16-95 03:43p REFPKG .CVR 0 10-16-95 03:34p
/
o ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE . INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMENT PRE-PANEL PREPARED BY: Mark S. Miller NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This information will be used by EICS to prepare the enforcement letter and Notice, as well as the transmittal memo to the Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit: 1 Occket Nos: 50-335 License Nos: DPR 67 Inspection Dates: July 2 - Auaust 28. 1995 Lead Inspector: Richard L. Prevatte
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is enclosed. [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [] Copies of applicable Technical Specifications or license conditions . cited in the Notice are enclosed. ]
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best <
fits the violation (s) (e.g.. Supplement I.C.2) I . B .1* I . C . 2. (b)* I . C . 6*
- As stated in new enforcement policy
- 4. What is the apparent root cause of the violation or problem?
Personnel error in maintenance combined with a failure to oerform adeogAta ; oost-maintenance testina and a failure to orovide adeauate acceotance i criteria for surveillance testina of PORVs. i
1 0
- 5. State the message that should be given to the licensee (and industry) through this enforcement action. l Post-maintenance and surveillance testina should be of sufficient scoce.
and acceptance criteria of sufficient technical riaor. to ensure comoonent l ODerab111tv. l
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation? Was it self-disclosing? Was it identified as a result of a generic notification?)
The condition was identified by control room operators when it was noted that ooeration of the PORVs durina surveillance testina did not result _in eXDeCted chanaes in RCS and cuench tank oarameters. The identification of the misalianed main disk auide was identified I by the licensee when the valves were removed from the system for insoection. Failure to oerform adecuate oost-maintenance and surveillance testina was identified by the licensee in course of a ricorous root cause effort.
- b. CORRECTIVE ACTION: Although we expect to learn more information i regarding corrective action at the enforcement conference, describe l preliminary information obtained during the inspection and exit !
interview. l The discrecant conditions were corrected by the licensee. See ; attachment. ' What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? The PORVs were declared inocerable. the unit was olaced in a condition not recuirina their coerability and 1 hen was cooled down and deoressurized. Immediate corrective actions were aoorooriate and the subiect failures were investiaated aoaressively. Short term corrective actions included oronerly assemblina and testina the sub1ect PORVs. addina a OC hold ooint to the PORV maintenance 3rocedure to insure )roDer disc auide installation and to reou4re a pench lif t test uncer air oressure. Additionally. the licensee chanaed the acceDtance criteria in the PORV surveillance testino orocedure recu1rina documentation of RCS oressure chance. PORV ta11010e temoerature chance. and ouench tank oressure. level and temoerature chanaes. What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis? Root cause determination was well-coordinated. timelv. and
. 1 comorehensive.
- c. LICENSEE PERFORMANCE: This factor takes .into account the last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): io violations involvina the ~ adeauacy of oost-maintenance testina lave been issued in the last two years. Identify the applicable SALP category, the rating for this category and the overall rating for the last two SALP periods, as well as any trend indicated: The sub.iect functional area is Maintenance and Surveillance. which was most recently rated SALP 1 (January 94). The orevious SALP oeriod. the area was rated a SALP 1.
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities for the licensee to discover the violation sooner such as through normal surveillances, audits 0A activities, specific NRC or industry notification, or reports by employees?
Prooer oost-maintenance testina would have been effective in identifyina the inocerable status of the PORVs. Additionally, adeauate surveillance testina would have detected the inocerability. The Drior occortunities to identifiv the sub.iect conditions is at the heart of this enforcement action.
- e. MULTIPLE OCCURRENCES: Were there multi)le examples of the violation identified during this inspection? lf there were, identify the number of examples and briefly describe each one.
Multiole occurrences have not been identified. exceot to the extent that the noted test failures aoolied to two PORVs.
- f. DURATION: How long did the violation exist?
Since November. 1994.
d ADDITIONAL COMMENTS / NOTES: See attached descriotion of the subiect events. Note that. in addition to v olations relatina to cost-maintenance and surveillance testinc adeauacy. a vio' ation of TS 3.4.13. reaardina PORV operability for LTOP. existec . The info r-tion in this document is current as of Auaust 22. 1995. 4
. . . ~ ~ _ . -. . . - . . - . . . - - . . - . _ _ - - . . ~ ._..~.---_- ..~ - . . .. __ . . - -
A $ n ESCALATION AND MITIGATION FACTORS (57 Fa 5791, February 18, 1992)
' IDENTIFICATION CORRECTIVE LICENSEE PRIOR mlLTIPLE DURATION ACTION PERFORNANCE OPPORTUNITY TO OCCURRENCES IDENTIFY
+/- SS +/ M +/ 1m +im +im +im i Licensee Timeliness of current Licensee should Multiple Used for identified (M) corrective violation is an have identified examples of significant
- (To be applied action (M) isolated violation vlotation regulatory j even if (Did NRC have failure that is sooner as e identified message to j licensee could to intervene to inconsistent result of prior during licensee. (E) have .
ecceeptish with licensee's opportunities inspection , identified the satisfactory good such as audits (only for SL I, ,
- violation short term or performance (M) (E) 11 or III l sooner) remedial action violetlens) (E) ,
(E)1 NRC identified Proeptly violation is opportsmities OTHER C(IISIDERATI(WS (E) dovetooed reflective of evellebte to . i schedule for licensee's poor discover 1.. Leget aspects and potential vlotation such long term or declining Litigation risks. corrective performance (E) es through action (M) prior 2.~' Negligence, careless dis ' notification . regard, willfulness and~ (E) management invotvesent Self. Degree of Prior Esse of earlier 3J' Economic, persenet or disclosing licensee performance and discovery (E) corporate sein-(M-251 if initiative (M) effectiveness there was (To develop of previous C Any other regulatory frase^ initiative to corrective corrective work factors that need to be identify root action for considered pending action actions and cause) root cause) similar with regard to licensing,- i violations caemiselon meetingf or press Licensee Adequacy of the SALP - Period of time identified as root cause Considers between 5.: What is the intended message a result of enelysis for SALP 1 - (M) violation and 1 for the licensee and the' generic the violation SALP 2 - (0) notification "trukstry? notification (M) SALP 3 - (E) received by (M) Licensee (E) . .. ~ . " " NOTES -"- - ~ ~ ^ Comprehensive Prior $1milarity 2 corrective enforcement between the action to history violation and t prevent including notification occurrence of escalated and (E) similar non-escalated ' violation (M) enforcement lamediate Level of corrective management action not review the taken to notification < restore safety received (E) , and compliance (E) mmm SAFETY SIGNIFICANCE: In determining the safety significance of a violation in conjunction with the enforcement process, the evaluation should consider the technical safety significance of the violation ' as well as the regulatory significance. Consideration should be given to the matter as a whole in light of the circunstances surrounding the violation. There may be cases in which the technicet safety significance of the matter is low white the process contro. felture(s) may be significant, and, therefore, the severity levet determinetton should be bes o more on the process control feiture(s) than on the technical safety issue. The following factors shrv,td also be considered: 1) Did the violation actually or potentially impact public health and safety? 2) What was the root cause of the violation?
- 3) Is the violation an isolated incident or is it indir,ative of a progreemetic breakdown? 4) Wes
_.. .t euere of or involved in the violation? 5) Did the vlotetton involve willfulness? I
- w. - - - - _ . + , . - ~ . . ._- _ _ .
l . 1 t la Proposed Violation A j
)
- 10 CFR 50, Appendix B, Criterion XI states, in part, that a test program shall be I
' established to ensure that all testing required to demonstrate that components will ;
perform satisfactorily in service and that the program shall include proof tests prior to l installation and operational testing. The criterion further states that test procedures shall i , include provisions to assuring that adequate test instrumentation is available and used. FPL Topical Quality Assurance Report TQR 11.0, revision 4, " Test Control," statest in l part, that a test program shall be established to assure that testing required to demonstrate that stmetures, systems and components will perform satisfactorily in service and that the program shall include proof tests prior to installation, operational tests, and retest after repair. TQR 11.0 further states that test procedures shall incorporate requirements and acceptance limits in the applicable design and procurement documentation. 4 A Contrary to the above, on November 5,1994, and on November 6,1994, Power , 1 Operated Relief Valves V-1404 and V-1402, respectively, were installed in the Unit 1 i ! Reactor Coolant System, placed into operation on November 22, and relied upon to be i operable for approximately nine months without adequate post-maintenance and j surviellance testing sufficient to provide reasonable assurance that the valves would perform satisfactorily in service. As a result of these failures, both Unit 1 PORVs were inoperable from the time of their reinstallation after maintenance until August 11,1995, I
- when the reactor coolant system was depressurized and vented. Examples are:
- 1. No post-maintenance bench test was performed to ensure that the valves' main discs would change state in a pressurized environment.
- 2. On November 25, 1994, and on Febmary 27, 1995, operational surveillance testing, performed under Administrative Procedure 1-0010125A, revision 39,
- Data Sheet 24, did not employ adequate test instrumentation to detect the i inoperability of both valves and did not employ test acceptance limits derived i from the the valves' design documentation. Specifically, the use of acoustic data,
; as opposed to system pressure reduction derived from valve capacity, to indicate valve position was insufficient to discern the difference between bypass flow
! through the PORV pilot valves and actual changes in main valve position. 4 This is a Severity Level II violation (supplement I). Proposed Violation B Technical Specification 3.4.13 requires, in part, that two Power Operated Relief Valves be operable in " Mode 4 when the temperature of any RCS cold leg is less than or equal to 304'F, Mode 5 and Mode 6 when the head is on the reactor vessel; and the RCS is not vented through a greater than 1.75 square inch vent." Contrary to the above, from November 22 through 27,1994, and from February 27 through March 6,1995, St. Lucie Unit I was in conditions requiring operable Power
I Operated Relief Valves but no operable releif valves in service. The inoperability of the , Power Operated Relief Valves resulted from a combination of personnel error during maintenance and inadequate post-maintenance t d surveillance testing. This is a Severity Level II violation (Supplement 1). 6 8 4 m_-__
0 St. Lucie Unit 1 PORY Inoperability Operational Events On August 9, the licensee performed ASME Section XI stroke testing on V-1402 and V-1404 (Unit 1 PORVs) per AP 1-0010125A, revision 39, " Surveillance Data Sheets," Data Sheet 24. The test was performed with RCS pressure controlled at 257 to 268 psig. The methodology of the test involved placing the PORV coritrol switches in " override," (which ensured that the valves would not open) removing High Pressurizer Pressure bistables from the RPS cabinets (which would send an "open" signal to the PORVs which would be blocked by the status of the - control switches), and then, for each PORV, placing the control switch in " normal," which would send the open signal to the PORV. The stroke time for each PORV was to be measured from the time the control switch was taken to " normal" to the time that acoustic monitors indicated that the subject valve had opened. Once a valve stroke time had been obtained, the subject valve's control switch was to be returned to override to close the valve. The results of the subject testing indicated that the valves did not stroke open. No acoustic signal was received in the control room. The licensee then returned the valves to service while questions of acoustic monitoring calibration and threshold levels were considered. The test was reperformed approximately one hour later with temporary acoustic monitors and the resulting acoustic signals indicated that both valves stroked in under one second. LTOP was placed back in service, but Operations personnel began to question the validity of the test results, as no changes were noted in either RCS or Quench Tank parameters. While evaluations were being conducted, the unit was taken to Mode 4. At 7:03 p.m. on August 9, the valves were retested and found to be inoperable based, in part, on observations of RCS and Quench Tank parameters. Each was declared out of service and the licensee entered TS 3.4.13 Action (c), which required depressurization of the RCS and venting through a 1.75 square inch or greater opening within l 24 hours, i f At 9:37 p.m., operators were directed by management to perform a cooldown of the RCS. When placing the SDC system in service, the SDC discharge relief valve lifted and would not rescat without securing the SDC pumps to reduce SDC system pressure at the relief valve. This issue will be discussed in a separate enforcement action; however, the inoperability of the SDC system (due to the relief valve issue) precluded the licensee from cooling down and depressurizing Unit 1. Consequently, the licensee entered TS 3.0.3 at 10:45 a.m. on August 10 and began a heatup to greater than 304'F, a plant condition for which TS 3.4.13 did not apply. 305"F was achieved at 11:53 a.m. The SDC system was returned to service on August 11. A cooldown was commenced at 6:25 a.m. the same day. The licensee made plans to re-enter TS 3.4.13 AS (c) during the cooldown, I and to create the required vent path by removing the bonnet of PCV-1100F, one of two l pressurizer spray valves, which would create the required vent path to RCS cold leg 131. The subject AS was entered at 7:15 a.m. on August 11 and exited at 8:40 p.m. the same day, when the system was vented. PORV Operation I
l l The PORV design in question is a Dresser Industries Model 31533VX-30. The valve is a 2.5" ; inlet by 4" outlet pilot operated valve with a relief capacity of 153,000 lbm/hr. The internals J of the valves are displayed in Figure.l. The valve, as installed in Unit 1, is actuated by a solenoid valve, which acts on the pilot valve operating lever to open the pilot valve. The open pilot valve creates a vent path from below the main disc of the main valve, through holes machined in the main disc guide, to the quench tank.
- The reduction in pressure below the main valve main disc allows the disc to move open (down, in Figure 1) under the force of system pressure acting on the main disc.
When pressure has been reduced below the applicable resent pressure (depending upon PORV mode - normal, LTOP low range, or LTOP high range), the solenoid valve is deenergized, which closes the pilot valve and isolates the vent path from below the main valve disc to the , quench tank. Once the vent path is isolated, pressure builds up below the main valve disc as ' system pressure is admitted to the space through an orifice in the main valve retainer plug. When pressure has been built up below the main valve disc in this manner, the disc is moved into a closed position under pressure aided by spring force. Dimenostic Maintenance The subject PORVs were removed on August 12 and placed on a test bench for lift tests to be conducted under air pressure. Both valves were tested at a number of pressures within the LTOP range and were found to be inoperable. Disassembly and inspection revealed that the main disc guide was installed upside down, with the holes (required to vent the space below the main disc) located at the upper extreme of the main disc cavity such that proper venting below the main valve disc could not take place. As a function of diagnosing the root cause, the licensee reversed the main disc guide o.ientations (to the proper orientation) and retested the valves under air pressure. Both valves tested satisfactorily. The licensee also sent a spare valve to Wylie Laboroatories for testing under water and steam pressure, as these conditions could not be established at the site. The spare PORV was tested under water and steam with the main disc guide misoriented (the as-found condition of the Unit 1 PORVs) at pressures ranging from LTOP pressures to NOP ranges. The PORV failed to open under any condition with the main disc guide misoriented. Additionally, it was found that: e Under water pressure at 335 and 450 psig,10-15 psig was developed at the discharge of the pilot valve, indicating that some leakage around the main disc guide was possible, but not enough to provide venting sufficient to open the PORV. I e- Under steam pressure from 50 psig to 450 psig in 50 psig increments, 20-60 psig was developed at the pilot valve discharge. e Under steam pressure at 2400 psig,1500-1800 psig was developed at the pilot valve discharge. 9
l l The pressuces and media flow detected at the pilot valve discharge indicated that acoustic data ! may be received during PORY testing without being indicative of a PORV changing state. Maintenance
!- The subject PORVs were last reworked in November,1994, as part of the Unit I refueling outage. The rework was conducted by employees of Furmanite, which were used by the
- licensee for outage-related valve work. The PORVs were each worked by the same two 4
workers. The work package which directed the rebuild invoked the licensee's procedure' 1-M-0037, revision 6, " Power Operated Valve Relief Valve Maintenance." The licensee determined that step 9.8 " reassembly of Main Valve," step 7, which directs the installation of the main disc guide, did not include a QC hold point to verify proper installation. It was noted that this is the j only component which can be installed improperly and result in undetected inoperability. The procedure was revised to include a QC Hold Point prior to the valves' reassembly.
. The inspector questioned the licensee as to post-maintenance testing requirements as applied'to
' the PORVs. The licensee stated that post-maintenance testing was limited to a bubble test for
- seat leakage prior to reinstallation. The inspector noted that 1-M-0037 only required the noted bubble test as post-maintenance testing and, in fact, contained a note explaining that lift set point 2
testing was not required, as the valve was lifted based upon solenoid valve input. The procedure
- did not require a proof that the valve would change state under presseure prior to installation, but did include a check for main disc mechanical freedom.
? In discussing post-nuintenance testing with the licensee, it was stated that, while no documented lift test existed, air lifts were typically performed as a function of preparing for seat leakage tests. It was explained that, upon initial reassembly, the PORVs rarely, if ever, satisfied seat leakage criteria due to relative misalignment between the main valve disc and its seat. As a . , result, the licensee stated that lifts under air pressure were performed as a matter of course to allow the mair. .lisc to orient itself properly against its seat. The inspector noted that the governing procedure included a note to this affect, but no evidence existed to indicate that lifts 4 had occurred on the test bench. The licensee stated that, in discussions with the Furmanite Supervisor who oversaw the rebuilding of the PORVs during the 1994 outage, the Supervisor stated that he recalled at least l' 6 lifts under air pressure per PORV in attempts to obtain satisfactory seat leakage tests. No documentation existed to validate the claim. The licensee stated that, when testing of the spare PORV at Wylic was complete, and the PORV was returned to the site, Furmanite was going to be allowed to rebuild the valve and demonstrate that lifts could be achieved with the main disc guide installed backwards. The inspector discussed the plausibility of such lifts with the valve vendor representative on site, who stated that, in principle, such lifts were possible it sufficient gcps existed between the main disc guide and the gasket below the guide. The results of the test
. are pending.
The inspector concluded that post-maintenance testing, described in 1-M-0037, was inadequate to verify that maintenance had been satisfactorily performed on the PORVs. As described below, surveillance testing was performed on the PORVs during unit heatup and repressurization
W c following the Unit 1 outage. However, the inspector concluded that insufficient testing had been performed on the PORVs, prior to installation, to obtain a reasonable assurance that the PORVs ' would perform satisfactorily in the LTOP conditions which would exist prior to the subject surveillance test. The inspector discussed the issue ^of post-maintenance testing with Operations personnel. It was confirmed that Operations had accepted the subject PORVs from maintenance with the- ; assumption that they had been properly tested and, as such, considered them operable upon : installation. The inspector found this assumption to be counter to the understanding of i Maintenance personnel, as in-situ surveillance testing was considered to be the post-maintenance test of the valve overhaul. The inspector reviewed PWOs 63/8104 and 63/8105, which directed , I&C to perform PORV solenoid valve inspection and testing on V-1402 and V-1404, respectively. Included in the task description of each PWO was a requirement to " Notify Ops ' Dept to perform valve stroke time verification test per QI 11-4/AP 1-0010125A DS-10." The referenced procedure and data sheet were the same as that described below for PORV stroke time testing. The inspector concluded that the Maintenance and Operations Departments were , under completely different impressions of the status of the valves. i Surveillance Testing l The inspector questioned the licensee as to whether any in-situ testing had been performed on 4 the PORVs since their installation during the 1994 outage. The licensee stated that two tests had been performed; one on November 25, 1994, with RCS pressure at 245 psia, and one on February 27, 1995, with RCS pressure at 1750 psia. Both tests were documented as ; satisfactory. The satisfactory results were, by procedure, based upon acoustic data, as opposed l to system parameter changes (e.g. RCS pressure, quench tank conditions). As stated above, ;
^
results from testing at Wylie indicated that sufficient flow could be developed through bypass around a misinstalled main disc guide (and then out an open pilot valve) to provide acoustic data without actual main valve movement. The inspector concluded that the acceptance criteria provided for verifying PORV operability , in OP 1-0010125A was insufficient to demonstrate valve operability in that tests performed on t November 25,1994, and February 27, 1995, did not detect the inoperability of the subject PORVs. PORV Operability 4 The inspector reviewed the licensee's activities with regard to root cause determination for the l' subject PORV conditions. In particular, the inspector noted the following: , e Bench testing of both PORVs, once removed from the system and prior to individual valve disassembly, indicated that the valves would not lift under air pressure at any process pressure from the LTOP range to the NOP range. ; e Disassembly of each PORV resulted in the discovery ofincorrectly installed main valve disc guides. i
bd _e ..Upon correction of main valve disc guide orientation alone (i.e. no other piece part changes or replacement) for each PORV, bench testing under air pressure resulted in satisfactory lifts.'
- Wylie laboratory testing of a spare PORV, under water and. steam, under pressure conditio"4 ranging from below LTOP setpoints to above NOP, mdicated L that no lift was possible with the main valve disc guide installed backwards.
As a result, the inspector concluded that the PORVs were inoperable from the time they were installed in the RCS during the 1994 refueling outage until they were removed and reworked in
- August,1995.
4 Imnet on Unit 2 Unit 2 is not susceptible to the same failure, as Unit 2 employs Garrett / Crosby PORVs, which are of distinctly different design. Additionally, the Unit 2 PORVs provide direct main valve position indication, provided by a indexing rod attached to the main valve disc which activates a reed switch. The inspector reviewed AP 2-0010125A, revision 43, " Surveillance Data Sheets," Data Sheet 24, which directed surveillance testing for Unit 2 PORVs. The inspector found that the procedure directed that stroke time be based upon indicated valve position change, as opposed to acoustic data. [ FIND OUT IF UNIT 2 PROCEDURE HAS BEEN REVVED TOO] Imnact on Unit 1 The St. Lucie Unit I design employs twc PORVs, which provide overpressure protection both during normal operation and for LTOP concerns. Additionally, the PORVs are employed in EOPs for once through cooling in the event of a loss of other core heat removal options. During power operations, PORVs are designed to open only in the event of a high pressure reactor trip, and are sized to allow the unit to suffer a loss of load trip from full power without lifting a pressurizer code safety valve. Accident analyses do not credit PORV operation. During low-mode conditions, the PORVs operate on one of two selectable LTOP setpoints, depending upon cold leg temperature and whether a heatup or cooldown is in progress. Following the Unit I refueling, the unit was filled solid on November 22. The RCS was pressurized and in a condition requiring LTOP from November 22 threigh November 27. The unit was subsequently at NOP until a Short Notice Outage (SNO) in February,1995. During the SNO, the unit was in conditions requiring LTOP protection from February 27 through March
- 6. Notably, on March 4,1994, Unit 1 experienced a loss of shutdown cooling event with the unit in a solid water condition. The condition was corrected by operators, but not before RCS pressure had exceeded the LTOP anticipatory alarm setpoint. No LTOP lift of PORVs was demanded or experienced (peak pressure was 343 psia, LTOP setpoint at the time was 350 psia).
On July 11, 1994, Unit I suffered a high pressure trip (see IR 95-14) which, according to the licensee at the time of the trip, included a lifting of both PORVs. The conclusion was supported at the time by the inherent design of the system, the fact that acoustic data indicated that the
PORVs lifted, and noted increases in Quench Tank temperature. The licensee is now doubtful that the PORVs lifted during the trip, based upon a review of data (which sugges'.ed that pressure drifted above the PORV setpoint, as opposed to plateauing) and of analyses which showed that the post-trip loss of heat source acts, in conjunction with steam reliefs to limit pressure increases. As regards once through cooling functions of the PORVs, the St. Lucie IPE includes PORV use in early post-accident heat removal for reactor trips, loss of pressure control events, loss of offsite power events, main steam line break accidents, and steam generator tube ruptures. The licensee performed a PRA analysis which quantified the change in CDF for common-mode failures in PORVs. The licensee determined that the Unit 1 CDF had increased by an approximate factor of 3 for the period of inoperability of the subject PORVs. With regard to LTOP concerns, the licensee analyzed the impact of a loss of LTOP PORV function for the energy and mass addition events in the original LTOP design basis. The licensee determined that, based upon current levels of Unit 1 fluence, the maiximum allowable vessel stress would not be exceeded for any of the previously-analyzed LTOP events. Pressum relief by pressurizer code safety valves, or shutdown cooling relief valves (depending upon the event considered), were found to be sufficient to limit peak pressures to below maximum allowable values. l l
- d a. A a , a w - A
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i I i } l 01-08-97 05:33p Directory H:\1950 PEN.ENF\95180STL.DIR\*.* Frce: 5,259,264 , 1
. Cu'r rent <Dir> .. Parent <Dir>
9516 .RPT 73,983 10-27-95 12:23p ATTENDEE. 67,568 10-11-95 04:22p BRIEF . MAT 109,566 09-22-95 03 :04p CHRON .REV 2,737 11-02-95 09:31a DISCERTI.BF1 12,906.11-01-95 09:06a DISCRETI.BRF 39,355 10-27-95 02:43p EAWPOST .PEC 72,473 10-11-95 05:24p EAWPRE .PEC 74,475 09-28-95 01:23p EN . 4,786 11-15-95 01:17p FINALSIG.SDE 31,541 11-14-95 08:42a LTRTOOE .REV 43,667 11-03-95 04:05p OECMMTS . 24,084 10-27-95 01:03p OECMMTS .112 27,083 11-03-95 11:01a OECMMTS .117 25,312 11-07-95 02:25p PKGREV . 12,527 11-02-95 11:43a QUEST . 43,077 09-05-95 02:36p , REFLIST . 0 10-16-95 03:43p REFPKG .CVR 0 10-16-95 03:34p i I I l l i i 1 f 9
~ _ ~ _ _
# o NUCLEAR RE U T COMMISSION I
- TTNT$ o i EE" HEMORANDUM T0: James Lieberman, Director Office of Enforcement FROM: Stewart D. Ebneter, Regional' Administrator
SUBJECT:
EA 95-180, FLORIDA POWER AND LIGHT COMPANY. ST. LUCIE UNIT 1. PROPOSED SEVERITY LEVEL III PROBLEM, USE OF DISCRETION TO
-IMPOSE $50,000 CIVIL PENALTY 1
Attached for your review and concurrence is the proposed enforcement action for the subject case. An Enforcement Action Worksheet is provided as Attachment 1. Attachment 2 consists of a draft letter to the licensee and a Notice of Violation. Attachment 3 contains the reference material appropriate to this case. Three violations were identified for (1) the failure to meet Technical S)ecification requirements to maintain the Pressure Operated Relief Valves (30RVs) operable when at low pressure conditions: (2) the failure to adequately identify and perform post-maintenance testing of the PORVs: and (3) the failure to perform adequate inservice testing of the PORVs. We propose that the issue be classified as a Severity Level III problem consistent with Supplement I.C.2.a of the Enforcement Policy: A system designed to prevent or mitigate a serious , safety event not being able to perform its intended function under certain
. conditions. Application of the civil penalty assessment process would have resulted in a fully mitigated civil penalty but due to the poor licensee performance in this case, discretion was applied to impose the base civil penalty.
This case is not exempt from the Office of Enforcement's timeliness requirements. Attachments: 1. Enforcement Action Worksheet
- 2. Draft Letter /NOV to Licensee
- 3. Reference Package cc w/atts: J. Goldberg 0GC R. Zimmerman. NRR CONTACT: B. Uryc RII ,
404-331-5505
o 4 ENFORCEMENT ACTION WOR.KSHEET Revision 1 Post-Conference Caucus / Final EA 95-180 ' Region II - Non De'egated Case Licensee: Florida Power and Light Company St. Lucie Nuclear Plant Docket No. 50 335 License No. DPR 67 Dated Inspection Ended: August 30, 1995
- 1. Brief Summary of Inspection Findings:
A detailed discussion of the inspection findings is provided in Inspection Report Nos. 50-335/95-16 and 50-389/95-16. A Severity Level III problem is proposed for: (1) the failure to meet Technical Specification requirements to maintain Pressure Operated Relief 1 Valves (PORVs) V-1404 and V-1402 operable when at low pressure conditions: (2) the failure to adequately identify and perform post-maintenance testing of PORVs V-1404 and V-1402; and (3) the failure to perform adequate 1 inservice testing of the PORVs. All three issues were combined into a Severity Level III problem because the combined failures to comply with regulatory requirements resulted in a ! common mode failure of the PORVs and the failure to detect the inoperable ! PORVs through required tcsting between November 1994 and August 1995. ) i
- 2. Analysis of Root Cause:
The licensee's root cause analysis as described at the predecisional enforcement conference was limited to the immediate deficiencies. However, the NRC ins)ection of this case and the licensee's corrective action indicates tlat the licensee recognizes that there are other root causes in management and control of maintenance and testing and commits to corrective actions that include comprehensive reviews of procedures.
- 3. Basis for Severity level (Safety Significance):
The safety significance of the proposed action is consistent with a Severity Level III. Enforcement Policy Supplement I.C.2.a: A system designed to prevent or mitigate a serious safety event not being able to perform its intended function under certain conditions. PROPOSED ENFORCmmT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE Attachment I
o En Action 3 EA 95 180
- 4. Identify Previous Escalated Action within 2 Years or 2 Inspections? None .
- 5. Identification Credit? N/A Note that the event was considered self-disclosing as a result of the failure to achieve required results in inservice testing.
- 6. Corrective Action Credit? Yes Immediate corrective actions included restoring the valves to an operable status, revising maintenance and test procedures, and conducting a comprehensive review of the valve failure. Planned long-term corrective actions included, in part, (1) a phased review of other maintenance and test procedures to ensure quality control attributes are identified and verified, and that post-maintenance and inservice testing adequately t demonstrates operability; (2) consolidating test groups under a single manager; and (3) training on accountability and administration in regard to control of contractors. AlthoL@. Paknesses were identified in root cause analysis for this event, the NRC deternied that credit was warranted for the factor of Corrective Action.
- 7. Candidate for Discretion? Yes Section VII.A of the Enforcement Policy allows for the use of discretion to
-propose a civil penalty where application of the factors woulo otherwise i result in a zero civil penalty to reflect the significance of the violation and convey the ap3ropriate regulatory message. This case involves a situation where t1e licensee's performance was particularly poor.
Specifically, multiple opportunities existed during routine activities conducted by diverse groups to recognize the inoperability of the PORVs. The failure of these diverse groups to ensure system operability and the resulting loss of a safety function required by Technical Specifications is a significant safety and regulatory concern. Rigorous maintenance controls, adequate oparator attention to diverse control board indications during testing, adequate management reviews of testing criteria and results, or adequate post trip data analysis during the July 1995 cnit trip should have detected that the PORVs were inoperable. Therefore, we propose that a base civil penalty be imposed in this case to ensure the appropriate regulatory message that programs must provide defense in depth to preclude common mode failures.
- 8. Is a Predecisional Enforcement Conference Necessary? Conducted 9/25/95 If yes, should OE or 0GC attend? Yes Should conference be closed? Closed through the random selection process.
PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR. OE w -..-e w
'~ C ,2
- 4 Engenen Action EA %-180 l l
- 9. Non Routine Issues / Additional'Information:
None
- 10. This Action is consistent with the Following Action (or Enforcement Guidance) previously issued: ],
Supplement I.C.2.a of the Enforcement Policy
- 11. Regulatory Message:
The NRC is particularly concerned that procedures and controls in diverse parts of the maintenance and testing process failed and led to a comon mode failure of the PORVs. In addition. opportunities to recognize the inoperability of the valves during a unit trip and during inservice tests were missed. The failure to maintain programs to provide defense in depth and preclude common mode failures is a significant regulatory concern.
- 12. Recommended Enforcement Action:
The recommended enforcement action is a Severity Level III problem. The post-conference caucus concluded that the licensee had no escalated - enforcement in the past two years and the licensee should be given credit for the factor of corrective actions. The basis for this credit is 1 discussed in Section 6 above. However, discretion was exercised to propose a base civil penalty because of poor licensee performance in this situation (Section 7 above.) j
- 13. This case meets the criteria for a Delegated Case. No
- 14. Should this action be sent to OE for full review? Yes i
Requires approval by the Deputy Executive Director for Nuclear Reactor ; Regulation, Regional Operations and Research due to the exercise of
~
discretion to impose a civil penalty.
- 15. Regional Counsel Review No Legal Objection Dated: October 11, 1995
- 16. Exempt from Timeliness: No Basis for Exemption: Not Applicable Enforcement Coordinator: Linda J. Watson 404-331-5534 Date: October 11. 1995 PflOPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE ,
WITHOUT THE APPROVAL OF THE DIRECTOR, OE '
EA 95-180 Florida Power and Light Company ATTN: Mr. J. H. Goldberg President - Nuclear Division P. O. Box 14000 Juno Beach, FL 33408-0420
SUBJECT:
NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY -
$50,000 (NRC Inspection Report No. 50-335/95-16 and 50-389/95-16)
Dear Mr. Goldberg:
This refers to the inspection conducted on August 9-30, 1995, at St. Lucie Nuclear Plant. The inspection included a review of the circumstances associated with the incorrect installation of a key component in both of the Unit 1 Power Operated Relief Valves (PORVs) resulting in inoperability of both PORVs. The results of our inspection were sent to you by letter dated September 8,1995. A closed predecisional enforcement conference was conducted in the Region II office on September 25, 1995, to discuss the apparent violations. the root causes, and your corrective actions to preclude recurrence. A list of conference attendees. NRC slides. and a copy of your presentation summary are enclosed. Based on the information developed during the inspection and the information you provided during the conference, the NRC has determined that violations of NRC requirements occurred. These violations are cited in the enclosed Notice of Violation and Proposed Iinposition of Civil Penalty (Notice) and the circumstances surrounding them are described in detail in the subject inspection report. Violation A, described in the enclosed Notice, involved the failure to meet Technical Specification requirements to maintain PORVs V-1404 and V-1402 operable when at low pressure conditions. The valves were inoperable because the main disc guide had been installed upside down during routine maintenance. Although the direct root cause of Violation A was the failure of contractor technicians to specifically follow the approved maintenance procedure, other weaknesses contributed to the errors. The maintenance activities were performed on both valves by the same technicians: however, additional controls were not in place to ensure operability and protect against a common mode failure such as verification of orientation of the main disc guide by quality control or independent verification by a second party. Violation B involved the failure to adequately identify and perform post-maintenance testing of PORVs V-1404 and V-1402 in order to demonstrate that the valves would perform satisfactorily in service after valve maintenance was performed. Although testing was performed to confirm that seat leakage - requirements were met, you failed to identify and perform testing to ensure that the valves would function as required under pressure. Testing to ensure satisfactory performance of valves in service is a requirement of 10 CFR Part 50, Appendix B. Criterion XI. Test Control. The root cause of this violation could involve several functional areas: however, the root cause you discussed in the PROPOSED ENFORCEMENT ACTION NOT FOR PU8 tlc DtSCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE Attachment 2
I O h FP&L 6 predecisional enforcement conference was limited to the immediate procedural deficiency. Violation C involved the failure to perform adequate inservice testing of the PORVs. The inservice testing performed at pressures greater than low temperature over pressure relied solely on the use of acoustic monitoring of valve discharge to indicate valve position. This method was not sufficient to discern the difference between bypass flow through the PORV pilot valves and actual changes in main valve position. At low pressure the inservice test was performed with the block valves open providing multiple alternative indications of PORV i position. The violation was caused by the reliance on one insufficient parameter
.rather than using diverse indications to determine valve position. '
4 The NRC relies on implementation of strong maintenance and testing programs to ensure operability of key components. The NRC is aarticularly concerned that your procedures and controls in diverse parts of tie maintenance and testing process failed and led to a common mode failure of the PORVs. In addition. > opportunities to recognize the inoperability of the valves during a unit trip and during inservice tests were missed. The safety consequences of these multiple errors were that the availability of both PORVs for heat removal in a post accident condition and for low temperature overpressure protection was lost. The failure to maintain programs that provide defense in depth to preclude common mode failures is a significant safety and regulatory concern. Therefore, these violations are clrsified in the aggregate in accordance with the " General Statement of Polic3 and Procedure for NRC Enforcement Actions" (Enforcement Policy). (60 FR 34381: June 30. 1995/NUREG-1600) as a Severity Level III problem. l . In accordance with the Enforcement Policy, a base civil
$50,000 is considered for a Severity Level III problem. penalty Because in the your amount of facility has not been the subject of escalated enforcement actions within the last two years, the NRC considered whether credit was warranted for Corrective Action in accordance with the civil penalty assessment provision in Section VI.B.2 of the Enforcement Policy. Your immediate corrective actions included restoring the valves to an operable status, revising maintenance and test procedures, and conducting a comprehensive review of the facts and circumstances which led to the valve failure. Your planned long-term corrective actions included in part. .
(1) a phased review of other maintenance and test procedures to ensure quality I control attributes are identified and verified and that post-maintenance and inservice testing adequately demonstrate operability: (2) consolidating test ! groups under a single manager; and (3) training on accountability and . I administration with regard to the control of contractors. Although weaknesses 1 were identified in the root cause analysis for this event. the NRC determined ! that credit was warranted for the factor of Corrective Action. In accordance with Section VII.A of the Enforcement Policy, the NRC may exercise discretion by proposing a civil penalty where application of the factors would otherwise result in a zero civil penalty to ensure that the proposed civil penalty reflects the significance of the circumstances and conveys the appropriate regulatory message. The NRC has weighed the circumstances of this case and finds that it involves a situation where your performance was particularly poor. S>ecifically, multiple opportunities existed during routine activities conducted )y diverse groups to recognize the inoperability of the PROPOSED ENFORCEMENT ACTION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
i FP&L 7 j > 1 PORVs. First, expected provisions to ensure valve operability during maintenance 1 on the PORVs were not implemented. Examples included the failure to include a ) quality control holdpoint for a critical point in the reassembly and the failure to employ independent verification methods when vulnerabilities to common mode failures were introduced by allowing the same individuals to work on the , redundant valve. Second, management reviews of testing criteria and results were ! inadequate. Engineering and your plant safety committee accepted post ! maintenance testing that only verified seat leakage prior to )utting the valves back in service. Third. Operations and Maintenance did not lave a common understanding of the scope of the post-maintenance testing recuired. As a result of this misunderstanding, the PORVs were placed in the RCS anc declared operable without reasonable assurance that the PORVs would perform satisfactorily in the low temperature over pressure conditions which would exist prior to performance of the routine surveillance test. Fourth, the engineering and management reviews of the ability of the acoustic monitors to provide a reliable indication of valve o)erabilty were inadequate. Your subsequent investigation of the event revealed t1at the PORV )ilot valves allowed sufficient bypass flow to actuate the acoustic monitors. A t1orough initial review could have identified this testing flaw. Fifth, operator attention to diverse control board indications during testing was lacking and only when the one monitoring indication, failed, parameter that was required, i.e., the acousticdid were getting. Sixth, an adecuate post trip data analysis during the July 1995 unit trip would have detectec that the PORVs were inoperable. Overall. the failure of these six opportunities to ensure system operability and the resulting loss of a safety function required by your Technical Specifications is a significant safety and regulatory concern. Therefore, to emphasize the importance of maintaining adequate and diverse methods to ensure system operability. I have been authorized, after consultation with the Director. Office of Enforcement and the Deputy Executive Director for Nuclear Reactor Regulation. Regional Operations and Research, to issue the enclosed Notice of Violation and Proposed Imposition of Civil Penalty (Notice) in the base amount of $50,000 for the Severity Level III problem. You are required to r'spond e to this letter and should follow the instructions specified in the enclosed Notice when preparing you response. In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections. the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements. In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice." a copy of this letter, its enclosure, and your response will be placed in the NRC Public Document Room (POR). To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without redaction. PROPOSED ENFORCEMENT ACTION . NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR OE
o 4 l FP&L 8 l The responses directed by this letter and the enclosed Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No. 96.511. Sincerely, i Stewart D. Ebneter , Regional Administrator i Docket No. 50-335 l License No. DPR-67 i
Enclosures:
- 1. Notice of Violation and Proposed :
Imposition of Civil Penalty l
- 2. List of Attendees
- 3. NRC Slides ;
- 4. Licensee Presentation Handout j cc w/encls: (See next page)
P 4 9 PROPOSED ENFORCEMENT ACTION NOT FOR PUSLIC DISQLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
FP&L 9~ cc w/encls: D. A. Sager. Vice President Bill Passetti St. Lucie Nuclear Plant . Office of Radiation Control P. O. Box 128 - Department of Health and Ft. Pierce. FL 34954-0128 Rehabilitative Services : 1317 Winewood Boulevard ' H N. Paduano'. Manager Tallahassee, FL 32399-0700 Lice: sing and Special Programs Florida Power and Light Company Jack Shreve P. O. Box 14000 Public Counsel Juno Beach, FL 33408-0420 Office of the Public Counsel c/o The Florida Legislature J. Scarola. Plant General Manager 111 West Madison Avenue. Room 812
.St. Lucie Nuclear Plant Tallahassee. FL 32399-1400 P. O. Box 128 Joe Myers. Director Ft. Pierce. FL 34954-0128 Division of Emergency Preparedness Robert E. Dawson Department of Community Affairs Plant Licensing Manager 2740 Centerview Drive .St. Lucie Nuclear Plant Tallahassee. FL 32399-2100 P. O. Box 128 Ft. Pierce. FL 34954-0218 Thomas R. L. Kindred County Administrator J. R. Newman. Esq. St. Lucie County Morgan. Lewis & Bockius 2300 Virginia Avenue 1800 M Street. NW Ft. Pierce. FL 34982 Washington, D. C. 20036 Charles B. Brinkman John T. Butler. Esq. Washington Nuclear Operations Steel. Hector and Davis ABB Combustion Engineering. Inc. ;
4000 Southeast Financial Center 12300 Twinbrook Parkway. Suite 3300 Hiami, FL 33131-2398 Rockville. MD 20852 ] l i PROPOSED ENFORCEMENT ACTMN - NOT FOR PUSUC pesCLOSURE WITHOUT THE APPROVAL 9F THE DMECTOR. OE
l
-FP&L, 10 91stribution w/encls:
)UBLIC
-JTaylor ED0 JMilhoan DEDR- .
SEbneter,'RII-LChandler, OGC
- JGoldberg.: OGC EJulian,.SECY-BKeeling. CA .
Enforcement Coordinators RI, RIII, RIV JLieberman, DE JGray.-0E DE:EA File (B, Sumers OE) (2) MSatorius, OE EHayden, OPA
'DDandois. OC- .
LTemper, OC GCaputo, OI EJordon, AE00 DWilliams OIG CEvans, RII BUyrc,-RII - KClark,.RII-
.RTrojanowski,RII CCasto, RII Klandis, RII (IFS Update) . JNorris, NRR GHallstrom, RII IMS:RII .
NUDOCS l NRC Resident Inspector I U.S. Nuclear Regulatory Com. 7585 South Highway A1A Jensen Beach, FL 34957-2010 PR9PpggD ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
NOTICE OF VIOLATION AND . PROPOSED IMPOSITION OF CIVIL PENALTY Florida Power and Light Company Docket No. 50-335 St Lucie Unit 1 License No. OPR-67 EA 95-180 During NRC inspections conducted on August 9-30. 1995. violations of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," (60 FR 34381: June 30.1995/NUREG-1600), the Nuclear Regulatory Comission proposes to impose a civil penalty pursuant to Section 234 of the Atomic Energy Act of 1954, as amended (Act), 42 U.S.C. 2282, and 10 CFR 2.205. The particular problem and associated civil penalty are set forth below: A. Technical Specification 3.4.13 requires, in part, that two Power Operated Relief Valves (PORVs) be operable in Mode 4 when the temperature of any RCS cold leg is less than or equal to 304 F. in Mode 5 and Mode 6 when the head is on the reactor vessel: and the RCS is not vented through a greater than 1.75 square inch vent. Technical Specification 3.4.13. Action Statement (c), recuires that, with both PORVs inoperable, at least one PORV be returnec to an operable status or that the RCS be completely depressurized and vented through a minimum 1.75 square inch vent within 24 hours. Contrary to the above, from November 22 through 27, 1994, and'from February 27 through March 6,1995, while St. Lucie Unit 1 was in one of the conditions specified in Technical Specification 3.4.13 requiring operabid PORVs, PORVs V-1404 and V-1402 were inoperable because the main disc guide had been installed upside down and the provisions of Technical Specification 3.4.13 Action Statement (c) were not met. (01013) B. 10 CFR 50, Appendix B. Criterion XI requires, in part, that a test 3rogram be established to ensure that all testing required to demonstrate tlat components will perform satisfactorily in service is identified and performed in accordance with written test procedures which contain the recuirements and acceptance limits contained in applicable design documents anc that the test program shall include proof tests prior to installation. FPL Topical Quality Assurance Report TOR 11.0 revision 4. Test Control, states, in part, that a test program shall be established to assure that testing required to demonstrate that components will perform satisfactorily in service is performed and that the program shall include proof tests prior to installation. Contrary to the above, after maintenance performed on November 4, 1995, the licensee failed to adequately identify and perform post-maintenance testing of Power Operated Relief Valves V-1404 and V-1402 to demonstrate that the valves would perform satisfactorily in service after valve maintenance was performed. Specifically the post-maintenance test performed did not include a verification that the valve would change state under pressure prior to installation. (01012) PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE
~
WITHOUT THE APPROVAL OF THE DIRECTOR. OE Enclosure 1
4 Notice of Violation and Proposed 2 Imposition of Civil Penalty C. 10 CFR 50.55a(f)(4)(11) requires, in part, that inservice tests to verify operational readiness.of valves, whose function is required for safety. conducted during successive 120-month intervals, must comaly with requirements of the latest edition and addenda of the ASME Code. Florida Power and Light Second Ten-year Inservice Inspection Interval Inservice Testing Program For Pumps and Valves. Document Number JNS-PSI. 203. Revision 5. states, in part, that, between February 11. 1988 and February 10. 1998, the St. Lucie Unit 1 ASME Inservice Inspection (IST) Program will meet the requirements of the ASME Boiler and Pressure Vessel Code (the Code). Section XI 1983 Edition. Section XI of the 1983 ASME Boiler And Pressure Vessel Code, article IWV-3000. Test Requirements. Section IWV-3400. Inservice Tests, requires. in part, that Category A valves shall be full-stroke exercised at least once every three months. Category A valves that cannot be exercised during plant operation shall be full-stroke exercised during cold shutdowns. Contrary to the above on November 25, 1994, and February 27, 1995, the licensee failed to adequately full-stroke exercise ASME Category A Power Operated Relief Valves V-1404 and V-1402. Specifically, operational surveillance testing, performed under Administrative Procedure 1-0010125A. revision 39. Data Sheet 24. did not include an adequate test to detect that the main disc guides in valves V-1404 and V-1402 were misoriented causing the valves to fail to stroke open. (01033)
. These violations represent a Severity Level III problem (Supplement I). This violation is applicable to Unit 1 only.
Civil Penalty - $50,000. Pursuant to the provisions of 10 CFR 2.201. Florida Power and Light Company is hereby required to submit a written statement or explanation to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission, within 30 days of the date of this Notice of Violation and Proposed Imposition of Civil Penalty (Notice). This reply should be clearly marked as a " Reply to a Notice of Violation" and should include for each alleged violation: (1) admission or denial of the alleged violation. (2) the reasons for the violation if admitted, and if denied the reasons why. (3) the corrective steps that have been taken and the results achieved. (4) the corrective steps that will be taken to avoid further violations, and (5) the date when full compliance will be achieved. Mt9 POSED ENFQRCEMENT ACTIO8L NOT_EOM PUSUC DISCLOSURg WITHOUT THE APPROVAL OF THE DIRECTOR, OE
_ _ _ _ . _ . . ~. 6 Notice of Violation and Proposed 3 , Imposition of Civil Penalty
-If an adequate reply is not received within the time specified in this Notice, an order or a Demand for Information may be issued as why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken. . Consideration may be given to extending the response time for good cause shown. Under the authority of Section 182 of the Act 42 U.S.C. 2232, this response shall be submitted under oath or affirmation.
Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalty by letter addressed to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission, with a check, draft, money order, or electronic transfer payable to the Treasurer of the United States in the amount of the civil penalty proposed above, or the cumulative amount of the civil penalties if more than one civil penalty is proposed, or may protest imposition of the civil penalty in whole or in part, by
.a written answer addressed to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission. Should the Licensee fail to answer within the time specified, an order imposing the civil penalty will be issued. Should the
' Licensee elect to file an answer in accordance with 10 CFR 2.205 protesting the civil p,enalty, in whole or in part, such answer should be clearly marked as an
" Answer to a Notice of Violation" and may: (1) deny the violation (s) listed in this Notice, in whole or in part, (2) demonstrate extenuating circumstances, (3) show error in this Notice, or (4) show other reasons why the 3enalty should not be imposed. In addition to protesting the civil penalty in w1 ole or in part, such answer may request remission or mitigation of the penalty.
In requesting mitigation of the proposed penalty, the factors addressed in Section VI.B.2 of the Enforcement Policy should be addressed. Any written answer l in accordance with 10 CFR 2.205 should be set forth separately from the statement l or explanation in reply pursuant to 10 CFR 2.201, but may incornorate parts of the 10 CFR 2.201 reply by specific reference (e.g., citing page end paragraph numbers) to avoid repetition. The attention of the Licensee is directed to the Other provisions of 10 CFR 2.205, regarding the procedure for imposing a civil penalty. Upon failure to pay any civil )enalty due which subsequently has been determined in accordance with the applica)le provisions of 10 CFR 2.205, this matter may be l referred to the Attorney General, and the penalty, unless compromised, remitted, , or mitigated, may be collected by civil action pursuant to Section 234c of the l Act. 42 U.S.C. 2282c. i The response noted above (Reply to Notice of Violation, letter with payment of civil Jenalty, and Answer to a Notice of Violation) should be addressed to: Mr. I James _ieberman, Director. Office of Enforcement. U.S. Nuclear Regulatory Commission One White Flint North, 11555 Rockville Pike. Rockville. MD 20852-2738. with a copy to the Regional Administrator. U.S. Nuclear Regulatory Commission. Region II and a copy to the NRC Resident Inspector at the St. Lucie facility. Because your res)onse will be placed in the NRC Public Document Room (PDR), to the extent possi)le, it should not include any personal privacy, proprietary, or l l PRoeo8ED ENFORCEMENT ACTION NOT FOR PUBLK: DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l Notice of Violation and Proposed 4 Imposition of Civil Penalty safeguards information so that it can be placed in the PDR without redaction. However if you find it necessary to include such information, you should clearly indicate the specific information that you desire not to be ) laced in the PDR. and provide the legal basis to support your request for with1olding the information from the public. Dated at Atlanta, Georgia l this day of October 1995 ' 6 t i i PROPOSED ENFORCEMENT ACTION NOT FOR PUBLE DISCLOSUME WITHOUT THE APPROVAL OF THE DIRECTOR. OE
LIST OF ATTENDEES Licensee J. Goldberg. President. Nuclear division D. Sager. Vice President. St. Lucie Site J. Geiger. Vice President. Florida Power and Light company (FPL) W. Bohlke, vice President. Engineering L. Bradow. Nuclear Assurance Manager L. Rogers. Systems and Component Engineering Manager J. Marchese. Maintenance Manager J. West Operations Manager R. Golden. Nuclear Information Coordinator . FPL Nuclear Regulatory Commission S. Ebneter. Regional Administrator. Region II E. Herschoff. Director. Division of Reactor Projects (DRP) A. Gibson. Director. Division of Reactor Safety (DRS) B. Uryc. Director. Enforcement and Investigation Coordination Staff K. Landis. Branch Chief. Reactor Projects Branch 3. DRP D. Prevatte. Senior Resi. dent Inspector. St. Lucie Nuclear Plant C. Evans. Regional Attorney L. Watson. Enforcement Specialist B. Schin. Project Engineer. DRP E. Lea Project Engineer. DRP G. Hopper. Reactor Engineer. DRS M. Satorius. Enforcement Coordinator. Office of Enforcement (by telephone) l l
)
Enclosure 2
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9516 .RPT 73,983 10-27-95 12:23p ATTENDEE. 67,568 10-11-95 04:22p BRIEF . MAT 109,566 09-22-95 03 : 04p CHRON .REV 2,737 11-02-95 09:31a DISCERTI.BF1 12,906 11-01-95 09:06a DISCRETI.BR7 39,355 10-27-95 02:43p EAWPOST .PEC 72.473 10-11-95 05:240 EAWPRE .PEC 74,475 09-28-95 01:23p EN . 4,786 11-15-95 01:17p FINALSIG.SDE 31,541 11-14-95 08:42a LTRTOOE .REV 43,667 11-03-95 04:05p OECMMTS . 24,084 10-27-95 01:03p OECMMTS .112 27,083 11-03-95 11:01a OECMMTS .117 25,312 11-07-95 02:25p PKGREV . 12,527 11-02-95 11:43a QUEST . 43,077 09-05-95 02:36p REFLIST . 0 10-16-95 03:43p REFPKG .CVR 0 10-16-95 03:34p i l l 1 1 l i 1 l l
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l ENFORCEMENT ACTION WORKSHEET 1 Revision 1 Post-Conference Caucus / Final EA 95 180 Region II - Non Delegated Case Licensee: Florida Power and Light Company St. Lucie Nuclear Plant Docket No. 50 335 License No. DPR 67 Dated Inspection Ended: August 30, 1995
- 1. Brief Sumary of Inspection Findings:
A detailed discussion of the inspection findings is provided in Inspection Report Nos. 50-33'3/95-16 and 50-389/95-16. A Severity Level III problem is proposed for: (1) the failure to meet Technical Specification requirements to maintain Pressure Operated Relief Valves (PORVs) V-1404 and V-1402 operable when at low pressure conditions: (2) the failure to adequately identify and perform post-maintenance testing of PORVs V-1404 and V-1402: and (3) the failure to perform adequate inservice testing of the PORVs. All three issues were combined into a Severity Level III problem because the combined failures to comply with regulatory requirements resulted in a common mode failure of the PORVs and the failure to detect the inoperable PORVs through required testing between November 1994 and August 1995.
- 2. Analysis of Root Cause:
The licensee's root cause analysis as described at the predecisional enforcement conference was limited to the immediate deficiencies. However, the NRC inspection of this case and the licensee's corrective action indicates that the licensee recognizes that there are other reot causes in management and control of maintenance and testing and comits to corrective actions that include comprehensive reviews of procedures.
- 3. Basis for Severity level (Safety Significance):
The safety significance of the proposed action is consistent with a Severity Level III, Enforcement Policy Supplement I.C.2.a: A system designed to prevent or mitigate a serious safety event not being able to perform its intended function under certain conditions. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCICSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE Attachment 1
l l l l Enforcement Action 2 Worksheet EA 95-180
- 4. Identify Previous Escalated Action within 2 Years or 2 Inspections?
None
- 5. Identification Credit? N/A i Note that the event was considered self-disclosing as a result of the failure to achieve required results in inservice testing.
- 6. Corrective Action Credit? Yes Imediate corrective actions included restoring the valves to an operable status, revising maintenance and test procedures, and conducting a comprehensive review of the valve failure. Planned long-term corrective actions included, in part, (1) a phased review of other maintenance and test procedures to ensure quality control attributes are identified and verified, and that post-maintenance and inservice testing adequately demonstrates operability: (2) consolidating test groups under a single manager; and (3) training on accountability and administration in regard to control of contractors. Although weaknesses were identified in root cause analysis for this event, the NRC determined that credit was warranted for the factor of Corrective Action.
- 7. Candidate for Discretion? Yes !
Section VII.A of the Enforcement Policy allows for the use of discretion to propose a civil penalty where application of the factors would otherwise result in a zero civil penalty to reflect the significance of the violation and convey the appropriate regulatory message. This case involves a situation where the licensee's performance was particularly poor. Specifically, multiple opportunities existed during routine i activities conducted by diverse groups to recognize the inoperability of the PORVs. The failure of these diverse groups to ensure system operability and the resulting loss of a safety function required by Technical Specifications is a significant safety and regulatory concern. Rigorous maintenance controls, adequate operator attention to diverse control board indications during testing, adequate management reviews of I testing criteria and results, or adecuate post trip data analysis during ! the July 1995 unit trip should have cetected that the PORVs were inoperable. Therefore, we propose that a base civil penalty be imposed in this case to ensure the a)propriate regulatory message that programs must provide defense in dept 1 to preclude common mode failures.
- 8. Is a Predecisional Enforcement Conference Necessary? Conducted 9/25/95 If yes, should OE or OGC attend? Yes Should conference be closed? Closed through the random selection process. i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE l
l 1 Enforcement Action 3 Worksheet EA 95-180
- 9. Non Routine Issues / Additional Information: ;
None
- 10. This Action is consistent with the Following Action (or Enforcement Guidance) previously issued:
Supplement I.C.2.a of the Enforcement Policy
- 11. Regulatory Message:
The NRC is particularly concerned that procedures and controls in diverse parts of the maintenance and testing process failed and led to a common mode failure of the PORVs. In addition, opportunities to recognize the inoperability of the valves during a unit trip and during inservice tests were missed. The failure to maintain programs to provide defense in depth and preclude cr~ on mode failures is a significant regulatory concern.
- 12. Recommended Enforcement Action:
The recommended enforcement action is a Severity Level III problem. The post-conference caucus concluded that the licensee had no' escalated enforceaent in the past two years and the licensee should be given credit for the factor of corrective actions. The basis for this credit is discussed in Section 6 above. However, discretion was exercised to propose a base civil penalty because of poor licensee performance in this situation (Section 7 above.)
- 13. This case meets the criteria for a Delegated Case. No
- 14. Should this action be sent to OE for full review? Yes Requires approval by the Deputy Executive Director for Nuclear Reactor Regulation. Regional Operations and Research due to the exercise of discretion to impose a civil penalty.
- 15. Regional Counsel Review No Legal Objection Dated: October 11, 1995
- 16. Exempt from Timeliness: No Basis for Exemption: Not Applicable Enforcement Coordinator: Linda J. Watson 404-331-5534 Date: October 11, 1995 fAOPOSED ENFORCEMENT ACTION . NOT FOR PUBUC OtSCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
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9516 .RPT 73,983 10-27-95 12:23p ATTENDEE. 67,568 10-11-95 04:22p BRIEF . MAT 109,566 09-22-95 03 : 04p CHRON .REV 2,737 11-02-95 09:31a DISCERTI.BF1 12,906 11-01-95 09:06a DISCRETI.BRF 39,355 10-27-95 02:43p EAWPOST .PEC 72,473 10-11-95 05:24p EAWPRE .PEC 74,475 09-28-95 01:23p EN . 4,786 11-15-95 01:17p FINALSIG.SDE 31,541 11-14-95 08:42a LTRTOOE .REV 43,667 11-03-95 04:05p OECMMTS . 24,084 10-27-95 01:03p , OECMMTS .112 27,083 11-03-95 11:01a OECMMTS .117 25,312 11-07-95 02:25p PKGREV . 12,527 11-02-95 11:43a QUEST . 43,077 09-05-95 02:36p REFLIST . 0 10-16-95 03:43p REFPKG .CVR 0 10-16-95 03:34p .i I . J 1 1 I i 1
i . . s ENFORCEMENT ACTION WORKSHEET Revision 1 Post-Conference Caucus / Final EA 95 180 . . Region II Non Delegated Case Licensee: Florida Power and Light Company St. Lucie Nuclear Plant , Docket No. 50 335 License No. DPR 67 , Dated Inspection Ended: August 30, 1995
- 1. Brief Summary of Inspection Findings:
A detailed discussion of the inspection findings are provided in Inspection Report Nos. 50-335/95-16 and 50-389/95-16. A Severity Level III problem is proposed for: (1) the failure to meet' Technical Specification requirements to maintain Pressure Operated Relief Valves (PORys) V-1404 and V-1402 operable when at low pressure conditions: (2) the failure to adequately identify and perform post-maintenance testing of PORVs V-1404 and V-1402: and (3) the failure to perform adequate inservice testing of the PORVs. All three issues were combined into a Severity Level III problem because the combined failures to comply with regulatory requirements resulted in a comon mode failure of the PORVs and the failure to detect the inoperable PORVs through required testing between November 1994 and August 1995. .
- 2. Analysis of Root Cause:
The licensee's root cause analysis as described at the predecisional enforcement conference was shallow and limited to the immediate procedural deficiencies. The licensee's corrective action however, shows that the i licensee recognizes that there are other root causes in management and control of maintenance and testing and commits to corrective actions that include comprehensive reviews of procedures. The letter to the licensee is drafted to be critical of their root cause analysis.
- 3. Basis for Severity level (Safety Significance):
- The proposed action is consistent with a Severity Level III violation: Supplement I.C.2.a: A system designed to prevent or mitigate a serious safety event not being able to perform its intended function under certain conditions' . PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSVSE WITHOUT THE APPROVAL OF THE DIRECTOR. OE i _.__.___.________m_ _ _ _ _ _ _ _ _ _ m _ -_ _ -- ---,y
4 5
- Enforcement Action 2 Worksheet EA 95-180
- 4. Identify Previous Escalated Action within 2 Years or 2 Inspections? None 5 .' Identification Credit? N/A Note that the event.was considered self-disclosing as a result of the failure to achieve required results in inservice testing.
- 6. Corrective Action Credit? Yes Imediate corrective actions included restoring the valves to an operable status, revising maintenance and test procedures, and conducting a comprehensive review of.the valve failure. Planned long-term corrective actions included, in part,-(1) a phased review of other maintenance and test procedures to ensure quality control attributes are identified and verified, and that post-maintenance and inservice testing adequately demonstrates operability; (2) consolidating test groups under a single manager; and (3) training on accountability and administration in regard to control of contractors. Although weaknesses were identified in root cause analysis for this event, the NRC determined that credit was Warranted for the factor of.Correctfve Action.
- 7. Candidate for Discretion? No
- 8. Is a Predecisional Enforcement Conference Necessary?- Conducted 9/25/95 If yes, should OE or 0GC attend? Yes should conference be closed? Closed through the random selection process.
- 9. Non Routine Issues / Additional Information:
None
- 10. This Action is' consistent with the Following Action (or Enforcement Guidance) previously issued:
4 Supplement I.C.2.a of the Enforcement Policy
- 11. Regulatory Message: . ;
The NRC is particularly concerned that procedures and controls in diverse parts of the maintenance and testing process failed and led to a common mode failure of the PORVs. In addition, opportunities to recognize the inoperability of the valves during a unit trip and during inservice tests were missed. The failure to maintain programs that provide defense in depth to preclude comon mode failures is a significant regulatory concern. PROPOSED ENPORCEMENT ACTION NOT POR PUBLIC DISCLQSURE WITHOUT THE APPROVAL OF THE DIRECTOR OE i i
f l Enforcement Action 3 Worksheet EA 95-180 1 l
- 12. Recommended Enforcement Action:
The recomended enforcement action is a Severity Level III problem. No civil penalty is proposed for the violation in that the post-conference caucus concluded that the licensee had no escalated enforcement in the past two years and the licensee should be given credit for the factor of corrective actions. The basis for this credit is discussed in Section 6 above.
- 13. This case meets the criteria for a Delegated Case. No
- 14. Should this action be sent to OE for full review? No E mail for informal review
- 15. Regional Counsel Review No Legal Objection Dated:
- 16. Exempt from Timeliness: No Basis for Exemption: Not Appli:able Enforcement CoorJ::iator: Linda J. Watson 404-331-5534 Date: September 28, 1995 PROPOSED ENrORCEMENT ACTION - NOT FOR PUBLIC DISCLOSUR(
WITHOUT THE APPROVAL OF THE DIRECTOR. OE
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I UNITED STATES [,a aa'uSo NUCLEAR REGULATORY COMMISSION ! s' " 1 REGION 11 O o 101 MARIE 1TA STREET, N.W., SUfTE 2000 i 0 8- ATLANTA, GEORGIA 303234100 August.30, 1996 k * * * , * ,f' MEMORANDUM T0: James Lieberman, Director Office of Enforcement FROM: Stewart D. Ebneter, Regional Administrator /s/ L. A. Reyes
SUBJECT:
EA 96-236 AND 96-249: FLORIDA POWER AND LIGHT COMPANY. ST. LUCIE NUCLEAR PLANT - NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY (Special Inspection Report Nos. 50-335/96-12 and 50-389/96-12) Attached for your review and concurrence is the proposed enforcement action L for the subject case. Although this case meets the criteria for issuance as a Regional action, it is being provided to you for formal review as a result of an agreement during the Jost conference caucus and the caucus consensus that the severity of the 10 C:R 50.59 violation be reviewed and reaffirmed. The issues discussed herein were identified during an inspection completed on July 12, 1996. As discussed in detail in the proposed enforcement action, we propose that a Notice of Violation (Notice) be issued to the licensee comprised of a Severity Level III violation and two Severity Level IV violations. The Severity Level III violation related to the licensee's failure to obtain Commission ap3roval prior to implementing a change to the Emergency Diesel Generator (EDG) ruel Oil Transfer System which was determined to involve an unreviewed safety question. The Severity Level IV violations involved four instances where the licensee failed to incorporate facility changes into annunciator response
. procedures or plant drawings. In addition, a non-cited violation is proposed for one of the configuration management violations which was licensee identified and promptly corrected.
A closed, predecisional enforcement conference was conducted with the licensee on August 19, 1996. At the conference, the licensee admitted the violations associated with configuration management as well as one exam)le of the 10 CFR 50.59 violation (setpoint issue). However, for the t1ree remaining examples of the 10 CFR 50.59 violation (temporary fire pump, control element drive control system enclosure, and isolation of EDG fuel oil line valve) the ' licensee stated that 10 CFR 50.59 did not apply or the NRC was employing a position contrary to standard industry practice. On August 19 and 22, 1996, enforcement caucuses were conducted between Region II and the Office of Enforcement. It was determined that the 10 CFR 50.59 violation regarding the EDG Fuel Oil Transfer system constituted an unreviewed safety question and met the criteria for a Severity Le. vel III violation. Application of the civil penalty assessment process resulted in a base civil penalty because the license had previous escalated enforcement action, the violation was identified by NRC, and corrective actions were appropriate. The remaining three examples of the 10 CFR 50.59 violations were determined not to be valid examples. In addition, the configuration management violations were recharacterized into two Severity Level IV
O violations and a non-cited violation. The draft letter and Notice to the licensee are attached and are consistent with this agreed upon approach. In reviewing the proposed violation in Part I of the draft Notice, you should be aware that there were discussions between the licensee and NRC at the time the licensee implemented the valve position change in question. Specifically, on July 7,1995, the day following completion of the licensee's 10 CFR 50.59 - evaluation, a conference call was conducted between the licensee, Region II (K. Landis and M. Miller), and the Office of Nuclear Reactor' Regulation (J. Norris), During this telephone call,'the licensee discussed their plans to reposition the valve, their safety evaluation, their planned additional administrative controls, and the environmental benefits of the change. Based
- on the recollection of several of the NRC participants in this call, it is not unreasonable that the licensee believed that there was a mutual understanding of the minimal safety significance of the change, given the specified compensatory measures, and that reasonable actions were being taken to both maintain the EDG operable while precluding an adverse environmental impact.
This discussion was mentioned by the licensee at the conference however, they did not provide any view as to the impact this discussion had on their failure to perform an adequate 10 CFR 50.59 evaluation; There are views among the i staff that based on NRC knowledge and involvement in this matter. the safety . significance of the violation, and the age of the violation (prior to increased NRC sensitivity to the UFSAR and 10 CFR 50.59) that mitigation of the civil penalty or severity level would be appropriate. No additional reference materials are being provided to with this submittal as all information was .previously provided to you in preparation for the initial enforcement panel and conference. This action is not exempt from the Office of Enforcement's timeliness requirements.
Attachment:
Draft Letter and Notice cc w/ attachment: R. Zimmerman, NRR J. Goldberg. OGC stNn 70 Pupt it OnnWNT WYVD Vf5 NO OFFICE R!l:DRP Ril:0RS RII:EICS RII:0RA Rll:0RA
$1GNATURE NAME JJohnson AGibson BUyre CEvans LReyes DATE 01 / / 9? 01 / / 97 01 / / 97 01 / / 97 01 / / 97 COPY? YES NO YES NO YE5 NO YE5 NO YES NO OFFICIAL RECORD COPY DOCUMiNT NAME: H:\l960 PEN.ENF\96236STL.DIR\PKGT00E THIS DOCUMENT CONTAINS PREDECISIONALINFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR OE
I e UNITED STATES
+4 g Moog'o NUCLEAR REGULATORY COMMISSION 3 S REGION ll
- O E 101 MARIETTA STREET, N.W., SUITE 2I00 0 8 .
ATLANTA, GEORGIA 303230190
\..... l EA 96-236 arid EA 96-249 Florida Power & Light Company l ATTN: T. F. Plunkett President - Nuclear Divisidn P. O. Box 14000 Juno Beach, FL 33408-0420
SUBJECT:
NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY -
$50.000 (NRC Special Inspection Report Nos. 50-335 and 50-389/96-12)
Dear Mr. Plunkett:
This refers to the inspection completed on July 12, 1996, at your St. Lucie - facility. The inspection included a review of selected aspects of your configuration management and 10 CFR 50.59 safety evaluation peograms. The results of our inspection were sent to you by letter dated July 26, 1996. A , closed, predecisional enforcement conference was conducted in the Region II office on August 19, 1996, with you and members of your staff to discuss the apparent violations, the root causes, and your corrective actions to preclude recurrence. A letter summarizing the conference was sent to you by letter dated ------ . Based on the information developed during the inspection and the information , you provided during the conference, the NRC has determined that violations of . NRC requirements occurred. The violations are cited in the enclosed Notice of Violation (Notice) and the circumstances surrounding them are described in detail in the subject inspection report. ; The violation in Part I of the Notice involves your failure to recognize an unreviewed safety question related to the implementation of a valve lineup change to the Emergency Diesel Generator (EDG) fuel oil transfer system. Specifically, in July 1995, the licensee implemented a change to the 2B EDG system to permit closing of a manual isolation valve from the Diesel Fuel Oil Storage Tank to the day tanks in order to minimize in ground fuel oil leakage between the two tanks. As part of the change, the licensee instituted administrative measures including dedication of. a non-licensed operator and procedural revisions to assure timely opening of the valve following an EDG start. Although a safety evaluation was performed which concluded that a six percent increase in the probability of loss of the 2B3 emergency buss resulted from the change, it erroneously concluded that no increase in the probability of a component failure was created. The NRC has concluded that two new failure modes were introduced by the change: potential failure of the THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
O-FPL 2 operator to unisolate the fuel oil line and failure of the manualcisolation valve to open. Therefore, both the possibility for a malfunction of a type different than any evaluated previously in the UFSAR was introduced, and the probability of a failure of a component important to safety was increased, representing a valid unreviewed safety question. At the conference, you stated that a safety evaluation was prepared for this 1 changa consistent with Florida Power and Light Company procedures and industry ,. guidance (NSAC-25). However, NRC's position with respect to an " increase in probability" differs. Although the NRC recognizes that the increase in pro'] ability of component failure was small, a normally passive com made active and an absolute increase in probability was realized. ponent was Notwithstanding the small probability increase, the violation in Part I of the Sotice is of significant regulatory concern because a change was made to the EDG system resulting in the emergence of an unreviewed safety question for which a license amendment and NRC approval was not sought. Further, such failures to com)1y with the requirements of 10 CFR 50.59 resulted in facility o)erations whic1 depart from the licensing and or design bases described in tie Updated Final Safety Analysis Report (USFAR). Therefore, the violation in Part I of the Notice is classified in accordance with the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy), q NUREG-1600, as a Severity Level III violation. In accordance with the Enforcement Policy, a base civil penalty in the amount of $50,000 is considered for a Severity Level III violation. Because your facilityhasbeenthesubjectofescalatedenforcementactionswithinthelast i 2 years , the NRC considered whether credit was warranted for Identification r and Corrective Action in accordance with the civil penalty assessment process described in Section VI.B.2 of the Enforcement Policy. In this case, the NRC l concluded that it is not appropriate to give credit for Identification because the violation was discovered by the NRC. With regard to consideration for 1 Corrective Action. at the conference you stated that your actions related to l the violation in Part I of the Notice included revision of engineerin, safety ! evaluation guidance to clarify the definition of an increase in probooility and issuance of a technical alert to all engineers regarding this issue. Further, although not directly related to this violation, additional emphasis ' has been placed on the importance of 10 CFR 50.59 and the UFSAR. Your recent actions in this regard include: (1) 10 CFR 50.59 reviewer certification: 4 (2) additional 10 CFR 50.59 training for designated staff: (3) 10 CFR 50.59
. procedural enhancements; and (4) implementation of the UFSAR Review Project. l
' 3 A severity Level 111 problem and prorosed civil penalty of $50.000 were issued on March 28.1996 (EA 96 040) related to a dilution event. A severity Level 111 violation and , proposed civil penalty were issued on November 13. 1995 (EA 95 180) related to inoperable power operated relief valves. 4 THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATlON . NOT FOR PUBLIC l DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE 4 [
Fr. 3 Based on the above, the NRC determined that credit was warranted for Correctfve Actfon resulting in the base civil penalty. Therefore, to emphasize the importance of performing safety evaluations for . facility changes affecting safety and of prompt identification of violations ,
- and in consideration of your previous escalated enforcement actions. I have ;
been authorized, after consultation with the Director. Office of Enforcement. l to issue the enclosed Notice of Violation and Proposed Imposition of Civil !' ! -Penalty (Notice) in the base amount of $50,000 for this Severity Level III violation. Violations A and B described in Part II of the Notice have been categorized at ~ Severity Level IV. The violations involve four instances where you failed to . effectively incorporate design changes into plant operating procedures or : drawings. These violations were NRC identified and are of concern because of , the potential for misleading operators and the similarity of the violations to annunciator res)onse procedure deficiencies identified during previous - inspections. T1e fifth apparent example of the configuration management violation discussed at the conference involved your failure to properly , incorporate the spent fuel pool heat load calculation into operational procedure limitations prior to initiating core off-load. For this issue, the
-NRC has decided to exercise discretion and characterize the violation as non-cited (NCV 50-335/96-12-01) in accordance with Section VII.B.1 of the c
Enforcement Policy. Specifically, you identified the violation and promptly instituted appropriate corrective action. j NRC has concluded that no violation occurred with respect to the three additional apparent failures to comply with 10 CFR 50.59 addressed in the subject inspection report and discussed at the conference. Specifically. (1) the Unit 2 Control Element Drive Mechanism Control System Enclosure was not required to be included in the UFSAR, and installation and subsequent : modifications did not require 10 CFR 50.59 safety evaluations: (2) the configuration of a temporary fire pump placed in stand-by during the 1996 . Unit 1 refueling outage did not require a 10 CFR 50.59 evaluation in that the configuration was as described in the UFSAR (i.e.. the discharge valve was
- closed and the pump was isolated from the system)
- (3) the failure to perform a 10 CFR 50.59 safety evaluation to change the setpoints and procedures for operating the fuel hoist was identified and corrected by you prior to actual fuel movement. This letter closes any further NRC action on these matters.
You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response. In your ; response, you should document the specific actions taken and any additional 1 actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future ; inspections, the NRC will determine whether further NRC enforcement action is r necessary to ensure compliance with NRC regulatory requirements. ; t THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBLIC ; DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE i
e FPL 4 In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice." a copy of
- this letter, its enclosure, and your response will be placed in the NRC Public Document Room (PDR). To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without redacti,on.
Sincerely. Stewart D. Ebneter Regional Administrator Docket Nos. 50-335. 50-389 License Nos. DPR-67. NPF-16 Notice of Violations and Proposed
Enclosure:
Imposition of Civil Penalty cc w/ encl: J. A. Stall Site Vice President ' St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce. FL 34954-0128 H. N. Paduano. Manager Licensing and Special Programs Florida Power and Light Company P. O. Box 1/100 Juno Beach. FL 33408-0420 J. Scarola Plant General Manager St. Lucie Nuclear Plant P. D. Box 128 Ft. Pierce. FL 34954-0128 E. J. Weinkam Plant Licensing Manager St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce. FL 34954-0218 cc w/ enc 1: (Cont'd on Page 5) THIS DOCUMENT CONTAMS PREDECISIONAL WFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
FPL 5
~ cc w/enci (Cont'd): ,
. J. R. Newman, Esq.. t Morgan,. Lewis'& Bockius 1800 M. Street. NW. -
. Washington, D. C. 20036
- John T. Butler, Esq. :
. Steel. Hector and Davis 4000 Southeast Financial Center Miami FL 33131-2398 ,
Bill Passetti Office of. Radiation Control , De)artment of Health and lehabilitative Services , 1317 Winewood Boulevard ! Tallahassee. FL 32399-0700 Jack Shreve. Public Cour ai Office of the Public Counsel c/o The Florida Legislature '
'111 West ~ Madison Avenue. Room 812 Tallahassee. FL 32399-1400 ;
Joe Myers, Director
- Division of Emergency Preparedness .
Department of Community Affairs 2740 Centerview Drive i Tallahassee, FL 32399-2100 Thomas R. L. Kindred i County Administrator , St. Lucie County 2300 Virginia Avenue Ft. Pierce. FL 34982 Charles B. Brinkman Washington Nuclear Operations ABB Combustion Engineering. Inc. 12300 Twinbrook Parkway. Suite 3300 Rockville. MD 20852 k f THis DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUSLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE f 8 4 %
e c.. i C FPL 6: Distribution' w/en.gl: PUBLIC-EJulian SECY BKeeling CA JTaylor. EDO JMilhoan. DEDR RZimeman, NRR SEbneter, RII
' LChandler. OGC
'JGoldberg. 0GC JLieberman. DE .
. Enforcement Coordinators RI. RIII. RIV EHayden CPA EJordan AE00 PRabideau. OC
. DDandois. OC-
.GCaputo. OI HBell DIG OE:EA File (B. Summers. OE) (2 letterhead)
MSatorius. OE AGibson, RII JJohnson. RII
.CEvans. RII Buryc RII:
KClark.' RII
- RTrojanowski. RII CCasto' RII Klandis RII JNorris NRR ABoland RII NRC Resident Inspector U.S. Nuclear Regulatory Comm.
7585 South Highway A1A Jensen Beach FL 34937-2010 SEND TO PUBt!C DOC (MNT R00* VES No 0FFICE Ril:DRP RI!:0RS RII:EICS R!l:0RA RII:0RA SIGNATURE NAME JJohnson AGibson Buyre CEvans tReyes-DATE 01 / / 97 01 / / 97 01 / / 97 01 / / 97 01 / / 97 COPY? YES NO YES NO YE5 NO YES NO YES NO 0FFICIAL RECORD COPY DOCUMENT NAME: H:\l960 PEN.ENF\96236STL.DIR\PKGT00E THIS DOCUMENT CONTAWS PREDECISIONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
e NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY Florida Power and Light Company Docket Nos. 50-335, 50-389 St.-Lucie Nuclear Plant License Nos. DPR-67. NPF-16 EA 96-236 and 96-249 As a result of an NRC inspection completed on July 12, 1996, violations of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy). NUREG-1600, the Nuclear Regulatory Commission aroposes to impose a civil penalty pursuant to Section 234 of the Atomic Energy Act of 1954, as amended (Act), 42 U.S.C. 2282, and 10 CFR 2.205. The particular violations and associated civil penalty are set forth below: I. Violations Assessed a Civil Penalty
'10 CFR 50.59, " Changes. Tests and Experiments," provides, in part, that the licensee may make changes in the facility as described in the safety analysis report (SAR) without prior Commission approval, unless the proposed change involves an unreviewed safety cuestion. A proposed change shall be deemed to involve an unreviewec safety question if the probability of occurrence of a malfunction of equipment important to safety previously evaluated in the SAR may be increased, if a possibility for an accident or malfunction of a different type than any evaluated previously in the SAR may be created, or if the margin of safety as defined in the basis for any technical specification is reduced.
Contrary to the above, in July 1995, the licensee made a change to the facility which involved an unreviewed safety question without prior , Commission approval. Specifically, the 2B Emergency Diesel Generator (EDG) fuel oil line was manually isolated to secure a through-wall fuel oil leak. In taking this action, the licensee introduced two new failure modes for the 2B EDG, which both increased the probability of occurrence of a malfunction of the EDG above that previously evaluated in the SAR and the possibility for malfunction of a different type than any evaluated previously in the SAR, resulting in an unreviewed safety question. (01013) This is a Severity Level III violation (Supplement I) Civil Penalty - $50,000 II. Violations Not Assessed a Civil Penalty i 10 CFR 50 Appendix B. " Quality Assurance Criteria for Nuclear Power ' Plants and Fuel Reprocessing Plants," Criterion III requires, in part, that measures be established to assure that applicable regulatory ' requirements and the design basis.for safety-related structures. THIS DOCUMENT CONTAINS PRtiDECISIONAL MpORMATION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE i
Notice of Violation and Proposed 2 Imposition of Civil Penalty systems, and components are correctly translated into specifications, drawings, procedures, and instructions. 1 Florida Power and Light Company Topical Quality Assurance Report. TOR 3.0 Revision 11 implements these requirements. Section 3.2.
" Design Change Control." provides, in part, that design changes shall be reviewed to ensure that implementation of the design changes is ;
coordinated with any necessary changes to operating procedures. In addition. Section 3.2.4. " Design Verification." provides, in part, that design control measures shall be established to independently verify the , design inputs, clesign process, and that the design inputs are correctly j incorporated into the design output. 1 A. Contrary to the above, the licensee failed to coordinate design j changes with the necessary changes to operating procedures as ' follows-
- 1. Plant Change / Modification (PC/M) 109-294 Setpoint Change to )
the Hydrazine Low Level Alarm (LIS-07-9) was completed on i January 6.1995, without assuring that affedted Procedure l ONOP 2-0030121. Plant Annunciator Summary, was revised. ! This resulted in annunciator S-10. HYDRAZINE TK LEVEL LO. l showing an incorrect setpoint of 35.5 inches in the ; procedure. l
- 2. PC/M 268-292. Intake Cooling Water Lube Water Piping Removal and Circulatory Water Lube Water Piaing Renovation, was completed on February 14.1994, wit 1out assuring that ;
affected Procedure ONOP 2-0020131. Plant Annunciator ' Summary, was revised. This resulted in the instructions for annunciator E-16. CIRC WTR PP LUBE SPLY BACKUP IN SERVICE, incorrectly requiring operators to verify the position of valves MV 21-4A and 4B following a safety injection actuation system signal to ensure they were deenergized and had no control room position indication.
- 3. PC/M 275-290. Flow Indicator / Switch Low Flow Alarm and Manual Annunciator Deletions, was comaleted on October 28, 1992, without assuring that affected )rocedure ON0P 2-0030131. Plant Annunciator Summary, was revised.
This resulted in the instructions for safety-related annunciators LA-12. ATM STM DUMP MV-08-18A/18B OVERLOAD /SS ISOL and LB-12. ATM STM DMP MV-08-19A/19B OVERLOAD /SS ISOL. incorrectly requiring operators to check Auto / Manual switch or switches for the manual position. (02014) ! This is a Severity Level IV violation (Supplement I). j I THIS DOCUMENT CONTAINS PREDECISIONAllNFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l
~
l l Notice of Violation and Proposed 3 Imposition of Civil Penalty l Contrary to the above, the licensee failed to assure that the ; B. design of the Circulating and Intake Cooling Water. System was correctly translated into plant drawings. Specifically, during implementation of PC/M 341-192. Intake-Cooling Water Lube Water Piping Removal and Circulatory Water Lube Water Piping Renovation, the as-built Drawing No. JPN-241-192-008 was not incorporated into Drawing No. 8770-G-082. Flow Diagram Circulating and Intake Cooling Water System. Revision 11. Sheet 2. issued May 9. 1995, for PC/M 341-192. This resulted in Drawing No. 8770-G-082 erroneously showing valves 1-FCV-21-3A and 3B and associated piping as still installed. (03014) This is a Severity Level IV violation (Supplement I). Pursuant to the provisions of 10 CFR 2.201. Florida Power and Light Company (Licensee) is hereby required to submit a written statement or explanation to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission, within 30 days of the date of this Notice of Violation and Prop. sed Im)osition of Civil Penalty (Notice). This reply should be clearly marked as a " Reply to a Notice of Viclation" and should include for each alleged violation: (1) admission or denial of the alleged violation. (2) the reasons for the violation if admitted, and if denied the reasons why. (3) the corrective steps that have been taken and the results achieved. (4) the corrective steps that will be taken to avoid further violations, and (5) the date when full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, an order or a Demand for' Information may be' issued as why the license should not be modified, suspended, or revoked or why , such other action as may be proper should not be taken. Consideration may be given to extending the response time for good cause shown. Under the authority of Section 182 of the Act. 42 U.S.C. 2232, this response shall be submitted under oath or affirmation. Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalty by letter addressed to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission, with a check, draft, money order, or electronic transfer payable to the Treasurer of the United States in the amount of the civil penalty proposed above, or the cumulative amount of the civil penalties if more than one civil penalty is 3roposed, or may protest imposition of the civil penalty in whole or in part. ay a written answer addressed to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission. Should the Licensee fail to answer within the time specified. an order imposing the civil penalty will be issued. Should the Licensee elect to file an answer in accordance with 10 CFR 2.205 protesting the civil penalty, in whole or in part, such answer should be clearly marked as an " Answer to a Notice of Violation" and may: (1) deny the violations listed in this Notice, in whole or in part (2) demonstrate extenuating circumstances. (3) show error in this Notice, or (4) show other reasons why the penalty should not be imposed. In addition to protesting the THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
Notice of Violation and Proposed 4 Imposition of Civil Penalty . civil penalty in whole or in part. such answer may request remission or mitigation of the penalty. Any written answer in accordance with 10 CFR 2.205 should be set forth separately from the statement or explanation in reply pursuant to 10 CFR 2.201.' but may incorporate parts of the 10 CFR 2.201 reply by specific
,eference (e.g., citing page and paragraph numbers) to avoid repetition. The attention of the Licensee is directed to the other provisions of 10 CFR 2.205, regarding the procedure for imposing a civil penalty.
Upon failure to pay any civil penalty due which subsequently has been determined in accordance with the applicable provisions of 10 CFR 2.205. this matter may be referred to the Attorney General and the penalty unless compromised, remitted, or mitigated, may be collected by civil action pursuant i to Section 234c of the Act. 42 U.S.C. 2282c. The response noted above (Reply to Notice of Violation, letter with payment of civil Senalty, and Answer to a Notice of Violation) should be addressed to: James _1eberman. Director. Office of Enforcement. U.S. Nuclear Regulatory Commission, One White Flint North 11555 Rockville Pike. Rockville. MD 20852-2738. with a copy to the Regional Administrator. U.S. Nuclear Regulatory Commission. Region.II and to the Resident Inspector at the St. Lucie facility. Because your res)onse will be placed in the NRC Public Document Room (PDR), to the extent possi ale, it should not include any personal privacy. 3roprietary, or safeguards information so that it can be placed in the PDR wit 1out redaction. However, if you find it necessary to include such information, you should clearly indicate the specific information that you desire not to be placed in the PDR. and provide the legal basis to support your request for withholding the information from the public. Dated at Atlanta. Georgia this ---- day of September 1996 P W I THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATiON . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE a
6 6 01-08 07:16p Directory H:\1960 PEN.ENF\96236STL.DIR\*.* Frco: 5,177,344
, Cur' rent <Dir> .. Parent <Dir>,
EAW .59 94,220 07-08-96 08:03p EN . 17,871 09-12-96 12:18p FINAL .SIG 30,937 09-19-96 06:29a PKGTOOE . 45,052 08-30-96 03:250 RABRIEF . 59,057 08-18-96 10:55p SCHEDULE. 4,443 09-12-96 01:47p l l 9
o UNTTED STATES fa pro NUCLEAR REGULATORY COMMISSION
/ '
y * "^" REGION 11 $ f AT , EORG' August 30, 1996 1 (*...+/ MEMORANDUM T0: James Lieberman Director Office of Enforcement , FROM: Stewart D. Ebneter. Regional Administrator /s/ L. A. Reyes
SUBJECT:
EA 96-236 AND 96-249: FLORIDA POWER AND LIGHT COMPANY. ST. LUCIE NUCLEAR PLANT - NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY (Special Inspection Report Nos. 50-335/96-12 and 50-389/96-12) Attached for your review and concurrence is the proposed enforcement action for the sub tct case. Although this case meets the criteria for issuance as a Regiona' action, it is being provided to you for formal review as a result of an agreement during the sost conference caucus and the caucus consensus that the severity of the 10 CFR 50.59 violation be reviewed and reaffirmed. The issues discussed herein were identified during an inspection completed on July 12, 1996.
'As discussed in detail in the proposed enforcement action, we propose that a Notice of Violation (Notice) be issued to the licensee comprised of a Severity Level III violation and two Severity Level IV violations. The Severity Level III violation related to the licensee's failure to obtain Commission ap3roval prior to implementing a change to the Emergency Diesel Generator (EDG) ruel Oil Transfer System which was determined to involve an unreviewed safety question. The Severity Level IV violations involved four instances where the licensee failed to incorporate facility changes into annunciator response procedures or plant drawings. In addition, a non-cited violation is proposed for one of the configuration management violations which was licensee identified and promptly corrected.
A closed, predecisional enforcement conference was conducted with the licensee on August 19, 1996. At the conference, the licensee admitted the violations associated with configuration management as sell as one exam)le of the 10 CFR 50.59 violation (setpoint issue). However, for the t1ree remaining control element examples of the 10 CFR 50.59 violation (temporary drive cont ol system enclosure, and isolation of EDG fuel oi fire pump,l line valve) the licensee stated that 10 CFR 50.59 did not apply or the NRC was employing a position contrary to standard industry practice. On August 19 and 22, 1996, enforcement caucuses were conducted between Region II and the Office of Enforcement. It was determined that the 10 CFR 50.59 violation regarding the EDG Fuel Oil Transfer system constituted an unreviewed safety question and met the criteria for a Severity Level III violation. Application of the civil penalty assessment process resulted in a base civil penalty because the license had previous escalated enforcement action, the violation was identified by NRC, and corrective actions were appropriate. The remaining three examples of the 10 CFR 50.59 violations were determined not to be valid examples. In addition, the configuration management violations were recharacterized into two Severity Level IV
i 4 ! violations and a non-cited violation. The draft letter and Notice to the ! licensee are' attached and are consistent with this agreed upon approach. i
.In reviewing the proposed violation in Part I of the draft Notice, you should >
be aware that there were discussions between the licensee and NRC-at the time the licensee implemented the valve position change in question. Specifically, on July 7, 1995, the day following completion of the licensee's 10 CFR 50.59-
. evaluation, a conference call was conducted between the licensee, Region II (K. Landis and M. Miller), and the Office of Nuclear Reactor Regulation (J. Norris). During this. telephone. call, the licensee discussed their plans to reposition the valve, their safety evaluation, their planned additional ;
administrative controls, and the environmental benefits of the change. Based on the recollection of several of the NRC participants in this call, it is.not onreasonable that the licensee believed that there was a mutual understanding of the minimal safety significance of the change, given the specified compensatory measures, and that reasonable actions were being taken to both maintain the EDG operable while precluding an adverse environmental impact. ; This discussion was mentioned by the licensee at the conference: however, they
~
did not provide any view as to the impact this discussion had on their failure to perform an adequate 10 CFR 50.59 evaluation. There are views among the staff that based on NRC knowledge and involvement in this matter, the safety significance of the violation, and the age of the violation (prior to increa;;ed NRC sensitivity to the UFSAR and 10 CFR 50.59) that mitigation of - the civil penalty or severity level would be appropriate. No additional reference materials are being provided to with this submittal as all information was previously provided to you in preparation for the initial enforcement panel and conference. This action is not exempt from the Office of Enforcement's timeliness !
, requirements.
Attachment:
Draft Letter and Notice l I cc w/ attachment: R. Zimerman, NRR 1 J. Goldberg. OGC j SfNO T1 PUBt10 00CtMENT ROOM ' VN N0 i OrFICE Ril:DRP RII.0RS RII:EICS RII. ORA R!!.0RA SIGNATURE NAME JJohnson AGibson BUyre CEvans LReyes DATE 01 / / 97 01 / / 97 01 / / 97 01 / / 97 01 / / 97 COPY? YES NO YES NO VES NO VE$ NO YES NO OFFICIAL RECORD COP) DOCUMiNT NAME: H:\l960 PEN.ENF\96236STL.DIR\PKGT00E THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION - NOT FOR PUSLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
, - + -_ - .. . .
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% UNITED STATES
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.....J EA 96-236 and EA 96-249 Florida Power & Light Company ATTN: T. F. Plunkett President - Nuclear Division P. O. Box 14000 Juno Beach FL 33408-0420
SUBJECT:
- NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY -
$50,000 (NRC Special Inspection Report Nos. 50-335 and 50-389/96-12)
Dear Mr. Plunkett:
This refers to the inspection completed on July 12. 1996, at your St. Lucie facility. The inspection included a review of selected aspects of.your configuration management and 10 CFR 50.59 safety evaluation programs. The results of our inspection were sent to you by letter dated July 26. 1996. A closed, predecisional enforcement conference was conducted in the Region II office on August 19, 1996, with you and members of your staff to discuss the apparent violations the root causes, and your corrective actions to preclude recurrence. A letter summarizing the conference was sent to you by letter dated ------ . Based on the information developed during the inspection and the information you provided during the conference, the NRC has determined that violations of NRC requirements occurred. The violations are cited in the enclosed Notice of Violation (Notice) and the circumstances surrounding them are described in detail in the subject inspection report. The violation in Part I of the Notice involves your failure to recognize an unreviewed safety question related to the implementation of a valve lineup change to the Emergency Diesel Generator (EDG) fuel oil transfer system. Specifically. in July 1995, the licensee implemented a change to the 28 EDG system to permit closing of a manual isolation valve from the Diesel Fuel Oil Storage Tank to the day tanks in order to minimize in ground fuel oil leakage between the two tanks. As part of the change, the licensee instituted administrative measures including dedication of a non-licensed operator and procedural revisions to assure timely opening of the valve following an EDG start. Although a safety evaluation was performed which concluded that a six percent increase in the probability of loss of the 283 emergency buss resulted from the change. it erroneously concluded that no increase in the probability of a component failure was created. The NRC has concluded that two new failure modes were introduced by the change: potential failure of the THIS DOCUMENT CONTAINS PREDECislONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE e p l
i FPL 2 operator to unisolate the fuel oil line and failure of the manual isolation
- valve to open. Therefore both the possibility for a malfunction of a type different than any evaluated previously in the UFSAR was introduced, and the probability of a failure of a component important to safety was increased, representing-a valid unreviewed safety question.
At the conference, you stated that a safety evaluation was prepared for this , change consistent with Florida Power and Light Company procedures and industry I guidance (NSAC-25). However. NRC's position with respect to an " increase in i probability" differs. Although the NRC recognizes that the increase in probability of component failure was small, a normally passive component was made active and an absolute increase in probability was realized. . Notwithstanding the small probability increase, the violation in Part I of the Notice is of significant regulatory concern because a change was made to the EDG system resulting in the emergence of an unreviewed safety question for which a license amendment and NRC approval was not sought. Further, such failures to comaly with the requirements of 10 CFR 50.59 resulted in facility o)erations whic1 depart from the licensing and or design bases described in t1e Updated Final Safety Analysis Report (USFAR). Therefore, the violation in Part I of the Notice is. classified in accordance with the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy). NUREG-1600, as a Severity Level III violation. , In accordance with the Enforcement Policy, a base civil penalty in the amount ' of $50.000 is considered for a Severity Level III violation. Because your l 1 facilityhasbeenthesubjectofescalatedenforcementactionswithinthelast 2 years , the NRC considered whether credit was warranted for Identification
, and Corrective Action in accordance with the civil penalty assessment process described in Section VI.B.2 of the Enforcement Policy. In this case, the NRC concluded that it is not' appropriate to give credit for Identification because the violation was discovered by the NRC. With regard to consideration for Corrective Action, at the conference you stated that your actions related to the violation in Part I of the Notice included revision of engineering safety evaluation guidance to clarify the definition of an increase in probability and issuance of a technical alert to all engineers regarding this issue.
Further, although not directly related to this violation, additional emphasis has been placed on the importance of 10 CFR 50.59 and the UFSAR. Your recent actions in this regard include: (1) 10 CFR 50.59 reviewer certification: (2) additional 10 CFR 50.59 training for designated staff: (3) 10 CFR 50.59 procedural enhancements: and (4) implementation of the UFSAR Review Project. t 3 A Severity Level III problem and proposed civil penalty of $50.000 were issued on March 28. 1996 (EA 96-040) related to a dilution event. A Severity Level 111 violation and proposed civil penalty were issued on November 13.1995 (EA 95-180) related to inoperable power operated relief valves. , l . THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR OE
O FPL 3 Based on the above. the NRC determined that credit was warranted for Corrective Action, resulting in the base civil penalty. Therefore, to emphasize the importance of performing safety evaluations for facility changes affecting safety and of prompt identification of violations and in consideration of your previous escalated enforcement actions. I have been authorized. after consultation with the Director. Office of Enforcement, to issue the enclosed Notice of Violation and Proposed Imposition of Civil Penalty (Notice) in the base amount of $50.000 for this Severity Level III violation. Violations A and B described in Part II of the Notice have been categorized at Severity Level IV. The violations involve four instances where you failed to effectively incorporate design changes into plant operating procedures or drawings. These violations were NRC identified and are of concern because of the potential for misleading operators and the similarity of the violations to annunciator res)onse procedure deficiencies identified during previous inspections. T1e fifth apparent example of the configuration management violation discussed at the conference involved your failure to properly incorporate the spent fuel pool heat load calculation into operational procedure limitations prior to initiating core off-load. For this issue, the NRC has decided to exercise discretion and characterize the violation as non-cited (NCV 50-335/96-12-01) in accordance with Section VII.B.1 of the Enforcement Policy. Specifically, you identified the violation and promptly instituted appropriate corrective action. NRC has concluded that no violation occurred with respect to the three additional apparent failures to comply with 10 CFR 50.59 addressed in the subject inspection report and discussed at the conference. Specifically. (1) the Unit 2 Control Element Drive Mechanism Control System Enclosure was not required to be included in the UFSAR, and installation and subsequent modifications did not require 10 CFR 50.59 safety evaluations; (2) the configuration of a ' temporary fire pump placed in stand-by during the 1996 Unit 1 refueling outage did not require a 10 CFR 50.59 evaluation in that the configuration was as described in the UFSAR (i.e., the discharge valve was closed and the pump was isolated from the system): (3) the failure to perform a 10 CFR 50.59 safety evaluation to change the setpoints and procedures for operating the fuel hoist was identified and corrected by you prior to actual fuel movement. This letter closes any further NRC action on these matters. You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response. In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements. THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
l FPL 4 In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter, its enclosure, and your response will be placed in the NRC Public Document Room (PDR). To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be , placed in the PDR without redaction. Sincerely. Stewart D. Ebneter Regional Administrator Docket Nos. 50-335, 50-389 License Nos. DPR-67. NPF-16
Enclosure:
Notice of Violations and Proposed t Imposition of Civil Penalty cc w/ encl: J. A. Stall Site Vice President St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce. FL 34954-0128 l H. N. Paduano. Manager Licensing and Special Programs
- Florida Power and Light Company P. O. Box 14000 Juno Beach, FL 33408-0420 J. Scarola Plant General Manager St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce. FL 34954-0128 E. J. Weinkam Plant Licensing Manager St. Lucie Nuclear Plant i P. O. Box 128 !
Ft. Pierce. FL 34954-0218 I I cc w/ encl: (Cont'd on Page 5) THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
FPL 5
- cc w/enci-(Cont'd): -
- J. R. Newman. Esq. '
Morgan. Lewis & Bockius-1800 M Street, NW. . Washington. D. C. 20036
~ John T. Butler. Esq.
Steel ~ Hector and Davis 4000 Southeast Financial Center
- Miami..FL 33131-2398- 4 Bill Passetti -
. Office of Radiation Control Deaartment of Health and r Rehabilitative Services
- 1317 Winewood Boulevard' ,
. Tallahassee FL 32399-0700 Jack Shreve. Public Counsel Office of the Public Counsel '
- c/o The Florida Legislature 111 West Madison Avenue. Room 812 Tallahassee FL 32399-1400 Joe Myers. Director Division of Emergency Preparedness Department of Community Affairs 2740 Centerview Drive
. Tallahassee FL 32399-2100 Thomas R. L. Kindred County Administrator St. Lucie County !
2300 Virginia Avenue 1
. Ft. Pierce. FL 34982 1 1
Charles B. Brinkman l Washington Nuclear Operations ; ABB Combustion Engineering.. Inc. I 12300 Twinbrook Parkway. Suite 3300 ) Rockville. MD 20852 i I l 1
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l THis DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBLIC 1 DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l 1 1 J
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'RZ1mmerman. NRR ,
2SEbneter RII LChandler. 0GC. 1 JGoldberg 0GC
-JLieberman OE' . . :
Enforcement Coordinators : LRI RIII. RIV: -
.EHayden. OPA
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OE:EA File (B. Summers. OE).(2 letterhead)
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RTrojanowski; RII CCasto, RII- 1 Klandis, RII o JNorris. NRR ABoland. RII NRC Resident Inspector i U.S. Nuclear Regulatory Comm. 7585 South Highway A1A- l Jensen Beach. FL 34957-2010
$END T1 PUBlic DOCtMENT R00M1 VES NO
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' SIGNATURE l NAME JJohnson- AGibson BUyrt CEvans LReyes DATE- 01 / ~ / 97 01 / / 97 01 / - / 97 01 / ' / 97 01 / / 97 COPY? VES NO VES NO YES NO VES NO YES - NO OFF1CIAL RiCORD COP) ,DOCUMiNT NAME: H:\1960 PEN.ENF\96236STL.DIR\PKGT00E THis DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE -
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4 NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY Florida Power and Light Company Docket Nos. 50-335. 50-389 St. Lucie Nuclear Plant License Nos. DPR-67 NPF-16 EA 96-236 and 96-249 As a result of an NRC inspection completed on July 12, 1996. violations of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy). NUREG-1600, the Nuclear Regulatory Commission proposes to impose a civil enalty pursuant to Section 234 of the Atomic Energy Act of 1954, as amended p(Act), 42 U.S.C. 2282, and 10 CFR 2.205. The particular violations and associated civil penalty are set forth below: I. Violations Assessed a Civil Penalty 10 CFR 50.59. " Changes. Tests and Experiments " provides, in part, that the licensee may make changes in the facility as described in the safety analysis report (SAR) without prior Commission approval, unless the proposed change involves an unreviewed safety cuestion. A proposed change shall be deemed to involve an unreviewec safety question if the probability of occurrence of a malfunction of equipment important to safety previously evaluated in the SAR may be increased, if a possibility for an accident or malfunction of a different type than any evaluated previously in the SAR may be created, or if the margin of safety as defined in the basis for any technical specification is reduced. Contrary to the above, in July 1995, the licensee made a change to the facility which involved an unreviewed safety question without prior Commission approval. Specifically, the 2B Emergency Diesel Generator (EDG) fuel oil line was manually isolated to secure a through-wall fuel , oil leak. In taking this action, the licensee introduced two new failure modes for the 2B EDG, which both increased the probability of occurrence of a malfunction of the EDG above that previously evaluated in the SAR and the possibility for malfunction of a different type than any evaluated previously in the SAR, resulting in an unreviewed safety question.(01013) This is a Severity Level III violation (Supplement I) Civil Penalty - $50,000 II. Violations Not Assessed a Civil Penalty 10 CFR 50. Appendix B, " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants." Criterion III requires, in part, that measures be established to assure that applicable regulatory requirements and the design basis for safety-related structures. THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l l
O. Notice of Violation and Proposed 2 ' Imposition of Civil Penalty systems, and components are correctly translated into specifications, drawings, procedures, and instructions. Florida Power and Light Company Topical Quality Assurance Report, TOR 3.0, Revision 11 implements these requirements. Section 3.2,
" Design Change Control." provides, in part, that design changes shall be i reviewed to ensure that implementation of the design changes is coordinated with.any necessary changes to operating procedures. In addition. Section 3.2.4. " Design Verification." provides,. in part, that design control measures shall be established to independently verify the design inputs, design process, and that the design inputs are correctly _
incorporated into the design output. A. Contrary to the above, the licensee failed to coordinate design + changes with the necessary changes to operating procedures as ' follows:
- 1. Plant Change / Modification (PC/H) 109-294 Setpoint Change to .
the Hydrazine Low Level Alarm (LIS-07-9), was completed on ' January 6.1995, without assuring that affected Procedure ON0P 2-0030121. Plant Annunciator Summary, was revised. This resulted in annunciator S-10. HYDRAZINE TK LEVEL LO, showing an incorrect setpoint of 35.5 inches in the procedure.
- 2. PC/M 268-292. Intake Cooling Water Lube Water Piping Removal and Circulatory Water Lube Water Piaing Renovation, was completed on February 14, 1994, witlout assuring that affected Procedure ONOP 2-0020131. Plant Annunciator ,
Summary, was revised. This resulted in the instructions for ! annunciator E-16, CIRC WTR PP LUBE SPLY BACKUP IN SERVICE, 1 incorrectly requiring operators to verify the position' of ' valves MV 21-4A and 4B following a safety injection actuation system signal to ensure they were deenergized and had no control .oom position indication.
~
I
- 3. PC/M 275-290. Flow Indicator / Switch Low Flow Alarm and Manual Annunciator Deletions, was com)1eted on October 28. I 1992, without assuring that affected 3rocedure l ONOP 2-0030131. Plant Annunciator Summary, was revised. '
This resulted in the instructions for safety-related annunciators LA-12. ATM STM DUMP MV-08-18A/18B OVERLOAD /SS : ISOL, and LB-12, ATM STM DMP MV-08-19A/19B OVERLOAD /SS ISOL. ! incorrectly requiring operators to check Auto / Manual switch ! , or switches for the manual position. (02014) This is a Severity Level IV violation (Supplement I). l I l THIS DOCUMENT CONTAWS PREDECislONAL WFORMATION NOT FOR PUSLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
Notice of Violation and Proposed 3 Imposition of Civil Penalty
.B. Contrary to the above, the licensee failed to assure.that the design of the Circulating and Intake Cooling Water System was correctly translated into plant drawings. Specifically during implementation of PC/M 341-192. Intake Cooling Water Lube Water Piping Removal and Circulatory Water Lube Water Piping Renovation, the as-built Drawing No. JPN-241-192-008 was not incorporated into Drawing No. 8770-G-082. Flow Diagram Circulating and Intake Cooling Water System. Revision 11. Sheet 2. issued May 9, 1995, for PC/M 341-192. This resulted in Drawing No. 8770-G-082 erroneously showing valves 1-FCV-21-3A and 3B and associated piping as still installed. (03014)
This is a Severity Level IV violation (Supplement I). Pursuant to the provisions of 10 CFR 2.201. Florida Power and Light Company (Licensee) is hereby required to submit a written statement or. explanation to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission, within 30 days of the date of this Notice of Violation and Proposed Imposition of Civil Penalty (Notice). This reply should be clearly marked as a " Reply to a Notice of Violation" and should include for each alleged violation: (1) admission or denial of the alleged violation. (2) the reasons for the violation if admitted, and if denied, the reasons why. (3) the corrective steps that have been taken and the results achieved. (4) the corrective steps that will be taken to avoid further violations, and (5) the date when full compliance will be achieved. If.an adequate reply is not received within the time specified in this Notice, an order or a Demand for Information may be issued as why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken. Consideration may be given to extending the response time for good cause shown. Under the authority of Section 182 of the Act. 42 U.S.C. 2232, this response shall be submitted under oath or affirmation. Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalty by letter addressed to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission, with a check, draft, money order, or electronic transfer payable to the Treasurer of the United States in the amount of the civil penalty proposed above, or the cumulative amount of the civil penalties if more than one civil penalty is 3roposed, or may protest imposition of the civil penalty in whole or in part. 3y a written answer addressed to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission. Should the Licensee fail to answer within the time specified. an order imposing the civil penalty will be issued. Should the Licensee elect to file an answer in accordance with 10 CFR 2.205 protesting clearly the as marked civil anp'- Answer to a Notice of Violation" and may:enalty, in whole or in p (1) deny the violations listed in this Notice, in whole or in part. (2) demonstrate extenuating circumstances. (3) show error in this Notice, or (4) show other reasons why the penalty should not be imposed. In addition to protesting the THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
l :, l l i L. ;
; i
- Notice of. Violation and Proposed 4 L Imposition.of Civil ~ Penalty ,
civil' penalty in whole or in part, such answer may request: remission or mitigation of.the penalty. Any written answer in accordance with 10 CFR 2,205 should be set forth -
' separately from the statement or explanation in reply pursuant to 10 CFR 2.201, but may incorporate parts of the 10 CFR 2.201 reply by specific reference (e.g., citing page and paragraph numbers) to avoid repetition. The .
attention of the Licensee is directed to the other provisions of 10 CFR 2.205, t regarding the procedure for imposing a civil penalty. , lipon failure to pay any civil penalty due which subsequently has been determined in accordance with the applicable provisions of 10 CFR 2.205, this matter may be referred to the Attorney General, and the penalty, unless compromised, remitted, or mitigated..may be collected by civil action pursuant ; to Section 234c of the Act. 42 U.S.C. 2282c. . The response noted above (Reply to Notice of Violation, letter with payment of civil Senalty, and Answer to a Notice of-Violation) should be addressed to: James .ieberman, Director, Office of Enforcement. U.S. Nuclear Regulatory 1
. Commission, One White Flint North.11555 Rockville Pike, Rockville. MD 20852-2738, with a copy to the Regional Administrator, U.S. Nuclear Regulatory i Commission, Region II and to the Resident Inspector at the St. Lucie facility. l Because your res)onse will be placed in the NRC Public Document Room (PDR), to i the extent possiale, it should not include any personal privacy, 3roprietary. l or safeguards information so that it can.be placed in the PDR witlout J redaction. However, if you find it necessary to include such information, you
. should clearly indicate the specific information that you desire not to be placed in the PDR, and provide the legal basis to support your request for I withholding the information from the public. l Dated at Atlanta, Georgia this ---- day of September 1996 ;
l l l l THIS DOCUMENT CONTAINS PREDECIslONAL INFORMATION NOT FOR PUSLIC DISCLOSURE WilHOUT THE APPROVAL OF THE DIRECTOR, OE
'j
.)
01-08-97 07:16p . Directory H:\1960 PEN.ENF\96236STL.DIR\*.*
. Fr;o : -5,177,344
- . ' Current <Dir> .. Parent <Dir>
EAW .59 94,220 07-08-96 08:03D- EN . 17,871 09-12-96 12:18p FINAL . .SIG 30,937 09-19-96 06:29a PKGTOOE . 45,052 08-30-96 03:25p RABRIEF . 59,057 08-18-96 10:55p SCHEDULE. 4,443 09-12-96 01:47p 5 i a d k 1 4
O i 1 ENFORCEMENT ACTION WORKSHEET . l INADEQUATE SAFETY EVALUATION PROGRAM
- PREPARED BY: John W. York DATE: July 7, 1996 NOTE: The Branch Chief of the responsible Division is responsible for preparation of this EAW and its distribution to attendees prior to an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e-mail [ENF.GRP, CFE, OEMAIL, JXL, JRG, SHL, LFD appropriate RII DRP. DRS: appropriate NRR. NMsS].
A Notice of Violation (without *boilerplate") which includes the recomended severity level for the violation is required, Copies of applicat4 Technical Specifications or license conditions cited in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed. This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. Signature Facility: St. Lucie Unit (s): 1 and 2 Docket Nos: 50 335, 389 License Nos: DPR 67, NPF 16 Inspection Report No: 96 ?? Inspection Dates: ?? Lead Inspector: John York
- 1. Brief Summary of Inspection Findings: [Always include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then, either sumarize the inspection findings in this section or reference and attach sections of the inspection report. Inspectors are encouraged to utilize the Noncompliance information Checklist provided in Enclosure 4 to ensure that the information gathered to support the violation is complete.)
Four examples were identified for violation of 50.59 requirements: Examole 1-The licensee concluded using PRA techniques that closing a manual valve (because of a leak in the transfer line) to the day tank of the EDG would increase the probability of a failure of the EDG by 6 %. However, in considering 50.59 criteria, the licensee concluded no increase in probability of component failure and therefore no Unreviewed Safety Question was identified. Examole 2-An enclosure was fabricated in a safety related area without ! performing a safety evaluation (50.59). i.e. no seismic analysis, etc. ExJmole 3-Fire protection plan requires that two 2300 gpm fire pumps be . operable at all times. During a refueling outage, electrical configuration was such that one of the pumps was removed from service and a smaller (750 gpm) pump was installed. This violated the fire PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i-f'
ENFORCEMENT ACTION ' WORK 8HEET protection configuration in the UFSAR and requires a 50.59 evaluation. Examole 4-The licensee changed the refueling hoist interrupt setpoints with only an engineering analysis. Since the set points were outside the UFSAR values a 50.59 safety analysis was required. See attached IR feeder and proposed NOV for details. l
- 2. Analysis of Root Cause: - -
Attention to detail, inadequate review of UFSAR in the 50.59 process.
- 3. Basis for Severity Level (Safety Significance): (Include example from the supplements. aggregation, repetitiveness, w111 fulness, etc.]
The number of exam)les indicate a programatic breakdown and lack of management oversig1t of 50.59 such that a safety concern is present t regarding compliance with the requirements of 50.59. Also, a condition existed where a required license amendment was not sought, i.e., an USQ existed and the condition was not sent to the NRC for review. , 4. Identif [by EA#.supplement, y Previous Escalated Action and Identification date.]Within 2 Years or 2 Inspections? None identified?
- 5. . Identification Credit? Depends on the example.
Item 1-Inspectors identified that the licensee did not identify an Unreviewed Safety Question. (No) Item 2-In response to an alarm and related maintenance, the licensee , identified that an enclosure in a cable spread room (safety related 4 area) did not have a safety analysis. (No) Item 3-Inspectors identified and questioned a different size fire pump. (No) Item 4-Licensee STA and safety commmittee identified that a 50.59 safety 4 analysis had not been performed. (Yes) Enter date Licensee was aware of issues requiring corrective action: [5/96]
- 6. Corrective Action Credit?
Brief summary of corrective actions: 1 In response to the' issues. the licensee adopted corrective actions which included: A NL Operator was assigned to operate the fuel valve for the EDG and a procedure was changed to indicate the com)ensatory action. In the other cases the recuired 50.59 safety analyses lave been performed. UFSARs are being changec and root cause determinations were initiated. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
. ENFORCEMENT ACTION NORKSHEET .
Explain application of corrective action credit: Corrective action appears to be of appropriate scope.
- 7. Candidate For Discretion? Yes.
Explain basis for discretion consideration: Licensee's performance has been considered superior in the past.
.8. Is A Predecisional Enforcement Conference Necessary? Yes Why:
To determine adequacy of licensee's proposed long-term corrective actions regarding the 50.59 safety analysis program. If yes, should OE or 0GC attend? [ Enter Yes or No]: Should conference be closed? [ Enter Yes or No]:
- 9. Non Routine Issues / Additional Information:
This issue should be discussed during a PEC along with the issues panelled the week of July 1. I l l I l l j PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTORi OE 3
ENFORCEMENT ACTION WORKSHEET
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: [EICS to provide] [lf inconsistent. include:]
l Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Message:
Control must be maintained over the screening and perfor:r.ance of safety analyses (10 CFR 50.59).
- 12. -Recommended Enforcement Action:
SL III-Under current NUREG 1600 examples I.C.5 and I.C.7 under draft examples I.C.10 and I.C.11.
- 13. This Case Meets the Criteria for a Delegated Case. [EICS - Enter Yes or No]
- 14. Should This Action Be Sent to OE For Full Review? [EICS - Enter Yes or No]
If yes why: l
- 15. Regional Counsel Review [EICS to obtain]
No Legal Objection Dated: J 1
- 16. Exempt from Timeliness: [EICS)
Basis for Exemption: Enforcement Coordinator: , DATE: l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
k ENFORCEMENT ACTION WORKSHEET ISSUES TO CONSIDER FOR DISCRETION t. c' Problems categorized at Severity Level I or II., a Case involves. overexposure or release of radiological material in excess of NRC requirements. o Case involves particularly poor licensee performance, o Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with OI regarding the case, whether or not the matter has been formally referred to 01, and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included. o Current violation is directly repetitive of an earlier violation. o Excessive duration of a problem resulted in a substantial increase in risk. a Licensee made a _ conscious decision to be in noncompliance in order to obtain an economic benefit. O Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) o Licensee's sustained performance has been particularly good, a Discretion should be exercised by escalating or mitigating to ensure that the proposed civil )enalty reflects the NRC's concern regarding the violation at issue and t1at it conveys the appropriate message to the licensee. Explain. , PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Enclosure 3 REFERENCE DOCUMENT CHECKLIST [] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: [- ] Licensee reports: [] Applicable Tech Specs along with baces: [] Applicable license conditions [] Applicable licensee procedures or extracts [] Copy of discrepant licensee documentation referred to in citations such as NCR inspection record, or test results [] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [] Other miscellaneous documents (List): i e R PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Safety Evaluations 10 CFR 50.59 Issues The inspectors reviewed and evaluated other 10 CFR 50.59 safety screenings and safety evaluations but the following four were identified as having problems. A. Safety Evaluation for Closing Manual Valve to EDG Fuel Supply
'The inspector reviewed the safety evaluation JPN-PSL-SENS-95-013,
-which was prepared to allow operation with a manual isolation valve closed in the 2B EDG fuel oil (F0) line from the DOST to the day tanks. The configuration was proposed when a leak was -
determined to exist in the underground line between the two tanks. The action was designed to minimize the amount of F0 released to the environment until the leak could be identified and corrected. As a compensatory measure, the licensee proposed dedicating an NLO to the task of opening the closed valve in the event of an EDG start. The licensee calculated that the EDG day tanks contained enough F0 to allow 126 minutes of EDG operation at full load before a transfer of F0 was required. The licensee then specified that the NLO would be required to open the valve within 20 minutes of an EDG start. Procedures were revised to include direction to open the valve on an EDG start, and administrative controls were put in place to ensure that the NLO would not be required to perform any other immediate response duties. Additionally, the licensee performed a response time test, alacing the operator at the G-2 warehouse (as far away from the EE as he could credibly be in the protected area) and requiring the NLO to proceed to the valve and open it. The NLO performed this task in approximately seven minutes. In considering the issue, the licensee employed PRA techniques to estimate the increase in the risk of the loss of the 283 bus due to a failure of either the operator to o)en the valve or a fail.ure of the valve to be able to be opened. T1e licensee concluded that the increase in probability was approximately 6 percent. However, in considering 10 CFR 50.59 criteria, the licensee concluded that no increase in the probability of failure of a component important to safety was created by the proposed action. The inspector questioned the licensee on this issue. The licensee explained that a deterministic conclusion of no increased probability was reached when the existence of procedural guidance and heightened awareness was balanced against the ap3roximate 6 percent increase in failure probability presented by t1e two new failure modes. In the context of regulatory compliance, the inspector noted that 10 CFR 50,59 was written in terms of absolute increases in the probabilities of failure represented by a proposed change. The inspector continued to question whether 10 CFR 50.59 criteria could ever be satisfied when new failure modes are imposed on a previously reviewed system (i.e whether added risk, once qualitatively established. could be completely mitigated). The inspector concluded that insufficient guidance existed from a PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
.. l regulatory perspective to take immediate issue with the licensee's 1
rationale. Further, the inspector concluded that the licensee had takeri prudent measures to ensure the continued operability of the 2B EDG while minimizing the F0 leak's effect on the environment. The inspector referred the question to WRR for resolution. After consideration of the-issue, the NRC determined that the ) actions taken by the licensee in this instance introduced two new ' failure modes to the EDG system: failure of the operator to ! unisolate the fuel oil line and failure of the manual isolation 1
- valve to cycle. As a result, the NRC has concluded that the licensee's actions necessarily increased the probability of a failure of a component important to safety and. as such.
rapresented an Unreviewed Safety Question, as defined in 10 CFR 50.59. Consequently, this action is identified as a violation (VIO 96 XX-ZZ. " Failure to Satisfy Requirements of 10 CFR 50.59"). B. Safety Evaluation for CEDMCS Enclosure On June 4,1996, a control room annunciator indicated that an undervoltage condition existed on the Control Element Drive t Mechanism Control System (CEDMCS). Operations responded to the CEDMCS equipment and noted that the CEDMCS enclosure was approximately 11 degrees warmer than normal. This enclosure is located in the cable s) reading room on the 43 foot elevation of the reactor auxiliary )uilding. Following this event, an STA In-House Event Report and Condition , Reports 96-1238. 96-1245 and 96-1325 were issued. Some of the following items with ap3ropriate plant corrective action tracking number were identified ay these reports: CEDMCS enclosure and air conditioning units did not appear on the plant's controlled drawings. (STAR 951320) CEDMCS enclosure air conditioning units were not seismic qualified. Final design was in process tc provide seismic , restraints for the air condition units. (PM 96-06-208) As part of the action for Condition Report 96-1325. a 10 CFR 50.59 safety evaluation was performed on the CEDMCS enclosure. The evaluation found that this air conditioned enclosure was erected in the early 1980's during the are-operational testing phase. This testing found that the CEDiCS enclosure required an air conditioned environment to prevent overheating of the four CEDMCS cabinets. The licensee's review determined that the design of the enclosure was acceptable, except that the air conditioning units and one air conditioning duct presented a hazard to safety related equipment in a seismic event. Therefore. seismic supports and restraints were provided for the air conditioning units and duct prior to the unit's restart on June 13. . The inspector reviewed the 10 CFR 50.59 evaluation provided for the design and installation of the seismic restraints and PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE I I 1
justification of the installation of the CEDMCS enclosure. This air conditioned enclosure was erected during the pre-operational , test phase in the early 1980's to provide c'oling for the CEA system. However, a 10 CFR 50.59 review wc 3pparently not performed when the enclosure was originally erected. The CEDMCS was ae:cribed in the UFSAR but the cooling system and enclosure for the CEDMCS were not described in the UFSAR. This was identified as another example of URI 50-335. 389/96-04-09.
" Failure to Update UFSAR".
The failure to perform an evaluation as required by 10 CFR 50.59 prior to making a change to the plant as described by the UFSAR is identified as a second example of Violation 50-389/96-XX-YY.
" Failure to Satisfy the Requirements of 10 CFR 50.59." Also, the failure of the licensee to impose design control measures on the fabrication of the CEDMCS room and its air conditioning system is an additional example of VIO 96-XX-XX. " Failure to Adequately Manage Configuration Control" C. Safety Evaluation for Inoperable Fire Pump During the S) ring 1996 Unit 1 refueling outage, one of the two Unit 1 EDGs lad been placed out of service to perform maintenance and modification work activities. Only one EDG was in service to provide power in the event of a loss of power event. To prevent a possible overload on the single EDG unit. a number of breakers to various components were opened and the units 480V electrical busses were crosstied in accordance with OP 1-0910024. Rev 6.
"Crosstying/Removai of 480V Buses." One of the components removed from service was Fire Pump 18. The breaker to this fire pump was opened on May 21. and this pump was removed from service and remained out of service on June 8. the end of this inspection.
period. ! AP 1800022. Rev 16. " Fire Protection Plan." Appendix A. Sections 2.2 and 2.3 required two fire pumps rated at a capacity of 2300 g)m to be operable at all times. Appendix A Section 4.1.A stated tlat with one of the two fire pumps inoperable, restore the inoperable equipment to service within seven days or provide an alternate backup pump within the next 30 days. Fire Pump AB had been out of service for 18 days. The compensatory measure established for this pump being out of service was the installation of a Jortable gasoline engine drive pump rated at 750 gpm. This pump lad been connected to take suction from the fire protection water storage tank for Fire Pump 1A. This alternate pump was not of the same capacity as one of the two required pumps and a justification was not provided to demonstrate that this pump was of adequate capacity to meet the maximum fire flow requirement for the safety related areas of the plant. The licensee initiated a CR to review this item. The licensee informed the inspector that the out of service pump could be restored to operability by restoring the existing open breaker to the closed position. Also, the 30 day time to provide PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
.=. - -.
L an alternate backup pump had not been exceeded. This met the
.j requirements of AP 1800022 for one pump being inoperable.
Resolution of the Condition Report (CR 96-1356) indi'ated that the c
-installation of the portable fire pump as the compensatory measure with one of the permanently installed fire pumps out of service violated the fire protection configuration as described in the UFSAR. . An engineering evaluation should have been prepared to justify and document the temporary configuration. This is a third example of Violation 50-335. 389/96-XX-YY " Failure to Satisfy the Requirements of 10 CFR 50.59".
l D. Safety Evaluation for Refueling Equipment Set Points Condition Report (CR) no.96-812 was issued by the licensee on the r.afety evaluation number SEFJ-96-020. St Lucie Unit 1 Refueling Equipment Underload and Overload Settings. The report stated that ; an engineering evaluation had been written to modify the overload and underload setpoints described in the FSAR without performing a 50.59 safety analysis / evaluation. These overload and underload ! load cell setpoints provide a margin to account for resistance : encountered while lifting or lowering fuel assemblies and prevent l exceeding the fuel assembly and refueling equipment design loads. The licensee had obtained information from the vendor for use in this Unit 1 refueling outage which would allow an increase in hoist interrupt from 10 percent to 200 pounds (approximately 18 percent for regular fuel assemblies). The original engineering analysis did not take into account that these changes in setpoint values would affect the FSAR and thus the deviation report (CR) was written. St. Lucie Quality Instruction (01) 2.0 Engineering Evaluation. Rev. 1 dated January'31, 1996 provides general requirements and guidance for the development and processing of engineering evaluations. This procedure references 01 2.1. 10 CFR 50.59 Screening / Evaluation. Rev. 1 dated harch 30. 1996, which states in part that the screening process is designed to determine whether the activity requires a complete 10 CFR 50.59 by asking a series of four questions. One cuestion. "Does the change represent a change to procedures as cescribed in the SAR?" should have been answered yes in the case of the original engineering analysis. The procedure also states that. " A positive response to any of the first four . . . . . . questions rewires a 10 CFR 50.59 evaluation". The Facility Review Group (FRG). the site safety committee noted that a safety evaluation was not present with the requested procedure change and returned the procedure to the engineering group for correction and the CR was written to identify the problem. This violation of procedure which required a safety evaluation (50.59) be performed is a fourth example of Violation 96-XX-YY.
" Failure to Satisfy the Requirements of 10 CFR 50.59" j i
PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE ! I
l ,. 1
- 10 CFR 50.59, _" Changes. Tests and Experiments." (a)(1) stated, in aart.
that a licensee may make changes in the facility as described in t1e "c safety analysis report without prior Commission approval, unless the proposed change involves an unreviewed safety question. 10 CFR 50.59 (a)(2) stated 'in part, that a proposed change shall be deemed to involve an unreviewed safety question if the probability of occurrence , of a malfunction of equipment important to safety areviously evaluated in the safety analysis report may be increased. ())(1) stated, in aart. the licensee shall maintain records of changes in the facility to tie . extent that these changes constitute changes in the facility as described in the safety analysis report or to the extent that u.2y constitute changes in procedures as described in the safety analysis report. These records must include a written safety evaluation which provides the bases for the determination that the change does not involve an unreviewed safety question. The following four examples of a violation of these requirement were identified. Example 1-Contrary to the above, in July 1995, the licensee made a , change to the facility which involved an unreviewed safety question when the 28 Emergency Diesel Generator fuel oil line from the fuel oil tank to the day tank was manually isolated to secure a through-wall fuel oil leak. In taking the action, the licensee introduced two failure modes ! into the 2B Emergency Diesel Generator (operator failure to open a manual isolation valve during a valid demand and the failure of a manual 1 solation valve to change state during an attempted opening) which necessarily increased the probability of occurrence of a malfunction of the Emergency Diesel Generator above that previously evaluated in the safety evaluation report. Example 2-Contrary to the above, the licensee erected an enclosure around the Control Element Drive Mechanism Control System during some period around 1984 without performing a safety evaluation. This non-safety related structure was erected in a safety related cable spread room. Example 3-Contrary to the above, during the 1996 Unit 1 refueling outage with only one operable emergency diesel generator in service, the licensee removed one of the two 2.500 gpm fire pumps from service and installed a temporary 750 gpm fire pum) arranged to take suction from fire protection water tank 1B and disc 1arge into the fire protection water system via fire hydrant No.12 without performing the required safety evaluation. The fire protection water supply system is shared by Units 1 and 2 and is described in UFSAR Appendix 9.5A, Section 3.0. Example 4-Contrary to the above, the licensee used an engineering evaluation to change the set points and procedures described in the FSAR for operating the fuel hoist without performing a 10 CFR 50.59 safety analysis / evaluation. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
4 l 1 3 , 1 01-08 05:25p Directory H:\1960 PEN.ENF\96040STL.DIR\*.* Prc3: 5,259,264
. Current <Dir> '
.. Parent <Dir> l EAW . 101,153 03-11-96 04:150 ENFINAL . 16,928 03-25-96 02:46p ;
FINALSIG.SDE 40,801 04-01-96 03:06p NAMEADDR.OPR 1,010 03-21-96 04:28p RABREIF . 96,672 03-11-96 03:42p REPORT . 142,495 03-11-96 03:23p 1 4 1 l a ! l 0
, \s 5
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4 ENFORCEMENT ACTION WORKSHEET e [ST LUCIE OVERDILUTION EVENT] PREPARED BY: R. Schin DATE: February 5, 1996 This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. Signature Facility: St. Lucie Unit (s): 1 Docket Nos: 50 335 License Nos: DPR 67 Inspection Report No: 50-335.389/96 01 Inspection Dates: January 26 30, 1996 Lead Inspector: R. Schin
- 1. Brief Summary of Inspection Findings:
Concern with operator attentiveness related to a reactivity addition event, and related operator violations of procedures:
- a. Operators failed to stop dilution when the proper amount had been added.
- b. There was inadequate watch turnover for the operator at the !
controls during dilution.
- c. Operators failed to follow the Conduct of Operations 3rocedure in l performi.ng the dilution procedure (lack of strict /ver)atim
~
compliance). '
- d. Operators failed to adequately report the event to licensee i management.
Also, operators exceeded the steady state licensed power limit of 2700 megawatts thermal (100% power). i In addition. the licensee nade a change to the procedures as described in the SAR without a 10 CFR 50.59 safety evaluation. See the attached draft NOV. General Description of Event. Detailed Sequence of Events. Summary of Draft Preliminary Ins)ection Findings. Control Room Diagram. CVCS Charging System Diagram. 3rocedures, and FSAR. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l
-a j 2 l
- 2. Analysis of Root Cause:
Operator inattentiveness to reactivity addition. I
- 3. Basis for Severity Level (Safety Significance):
; I ._C . 3 Inattentiveness to duty on the part of licensee personnel, while adding reactivity to the reactor, and I.C.7 A breakdown in the control of licensed activities involving a i number of violations that are related that collectively represent a I significant lack of attention or carelessness toward licensed l responsibilities.
i
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections? l EA 95-180 (EEI 95-16-01): LTOP inoperability due to PORV failure )
- Event date 8/9/95
- 5. Identification Credit ? No Identified through an event. The licensee initiated an In-House Event Report and gave a copy to the NRC resident inspector promptly after the event. The event becurred at approximately 0220 on January 22, 1996.
Missed opportunities:
- a. In response to SOER 94-02, dated September 1994, which described a !
> similar Turkey Point overdilution event and several inadvertent i dilution events at other utilities. the licensee reviewed the St. Lucie operating procedures related to dilution and concluded that no changes were needed. This was a missed o)portunity to ; strengthen operating procedures to prevent t1e 1/22/96 i overdilution event. l
- b. The Unit 2 dilution procedure had been changed in December 1995.
but not the Unit 1 procedure, to more accurately describe dilution the way the operators had performed it for years (in manual and direct to the charging pumas). During the event, manual dilution could not be accomplished )y using the Unit 1 procedure in compliance with the Conduct of Operations (strict / verbatim compliance).
- 6. Corrective Action Credit? Yes
~ The licensee initiated an In-House Event Report summarizing the event and began distribution of- that report within about four hours after the event. The licensee also immediately removed the reactor operator who had initiated the event from licensed duties, promptly issued a Night Order and conducted training on the event with operators on each shift: . revised the Unit 1 procedure for dilution so that manual dilution could be performed by strict compliance'to the procedure steps: revised the Conduct of Operations procedure to require the R0 to get prior . approval PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, DE
4 3 from the SR0 for dilution /boration, the SR0 to directly supervise dilution /boration, no R0 or SR0 turnover during dilution /boration, and RTGB walkdown prior to R0 or SR0 short term relief; and initiated further review of the event, Weaknesses in the licensee's corrective actions included:
- a. Potential VIO of 10 CFR 50.59: The revised procedure (after the event) did not support the FSAR Chapter 15 accident analysis assumptions on how dilution was performed. The revised
' described dilution in manual (with no automatic shutoff) procedure and directly to the suction of the charging pumps. The FSAR assumed dilution in automatic (with an automatic shutoff) and to the VCT (where the demineralized water would mix with boric acid solution before going to the suction of-the charging pumps and result in a lower rate of reactivity addition). The licensee had not -
performed a safety analysis of this difference and had not revised the procedure and/or FSAR to make them agree.
- b. The revised procedure for manual dilution (after the event) did .
not require the operator at the controls to remain by the dilution controls and to closely monitor the dilution during a manual dilution with no automatic shutoff.
- c. The licensee initial investigation of the event was not thorough in that it concluded that maximum reactor power was 100.2%.
Subsequent review by the NRC and licensee found that maximum reactor power was approximately 101.18%.
- 7. Candidate For Discretion? [See attached list] Yes - potential escalation.
During the last year, the licensee's performance in Operations has declined from SALP 1 to SALP 2 (predecisional). There have been several operator violations of procedures that are, in part, related to the current violation:
- 1) VIO 335/94-22-02, " Improper Modification of Control Room Logs".
November 25. 1994
- 2) NCV 335/95-07-0 . " Failure to Follow Shutdown Cooling Operating Procedures", AL il 19, 1995
- 3) VIO 335/95-15-01. " Failure to Follow Procedures and Block MSIS Actuation", October 16. 1995
- 4) VIO 335/95-15-02. " Failure to Follow Procedures during RCP Seal restaging", October 16, 1995
- 5) VIO 335/95-15-03, " Failure to Follow Procedure and Document abnormal valve position in the Valve Switch Deviation toq".
October 16. 1995 PROPOSED ENFORCEMENT ACTION NOT FOR PUBL;C DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
J A. d-. 4
- 6) VIO-335/95-15-04. " Failure to Follow Procedures during Alignment of Shutdown Cooling System". October 16. 1995
- 7) VIO 389/95-18-01. " Failure to Follow Procedures and Maintain Current and Valid Log Entries in the Rack Key Log and Valve Switch Deviation Log". November 27. 1995
- 8) VIO 389/95-21-02. " Failure to Follow the Equipment Clearance Order Procedure and Require Independent Verification of a TS Related Component". December 8. 1995 All of the above VIO/NCVs involved licensed operators with a licensee corrective action commitment to strict adherence to procedures.
- 8. Is A Predecisional Enforcement Conference Necessary?
Yes Why: There is substantial interest in this event and in the NRC message to the licensee and to the industry. The message for this enforcement action should be that operators must treat Dilution /Boration as seriously as control rod manipulations. Also, that unusual operations events must be transmitted promptly to management. If yes. should OE or 0GC attend? Yes Should conference be closed? No
- 9. Non Routine Issues / Additional Ir^;vtion:
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: 1.C.3 Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Nessage: The message for this enforcement action should be that operators must treat Dilution /Boration as seriously as control rod manipulations. Also, that unusual operations events must be transmitted promptly to management.
- 12. Recommended Enforcement Action: SLIII with CP
- 13. This Case Meets the Criteria for a Delegated Case. No P
- 14. Should This Action Be Sent to OE For Fuli Review? No, informal review.
- 15. Regional Counsel Review To be determined at a later date.
No Legal Objection Dated: PROPOSED ENFORCEMENT ACTION NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR OE
4 5
- 16. Exempt from Timeliness: No Basis for Exemption:
Enforcement Coordinator: DATE: 4 4 4 l I h PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
j
)
6 1 ENFCRCEMENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION a Problems categorized at Severity Level I or II. O Case involves overexposure or release of radiological material in excess of NRC requirements. - a Case involves particularly poor licensee performance. O Case (may) involve willfulness. Information should be included to i address whether or not the region has had discussions with OI regarding ! the case, whether or not the matter has been formally referred to 01, and whether or not 01 intends to initiate an investigation. A ' description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or i management involvement should also be included. '
'xo Current violation is directly repetitive of an earlier violation (in part).
o Excessive duration of a problem resulted in a substantial increase in risk. j 1 o Licensee made a conscious decision to be in noncompliance in order to I obtain an economic benefit. O Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) o Licensee's sustained performance has been particularly good, o Discretion should be exercised by escalating or mitigating to ensure that the proposed civil 3enalty reflects the NRC's concern regarding .the violation at issue and tlat it conveys the appropriate message to the licensee. Explain. I. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
7 Enclosure 3 REFERENCE DOCUMENT CHECKLIST [] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: [] Licensee reports: [] Applicable Tech Specs along with bases: [x] Applicable license conditions [x] Applicable licensee procedures or extracts
' [' ] Copy of discrepant licensee documentation referred to in citations such as NCR. inspection record, or test results
[x] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [] Other miscellaneous documents (List): I PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l
.. J
8 PROPOSED VIOLATION A. Technical Specification (TS) 6.8.1.a recuired that written procedures be established, implemented, and maintainec covering the activities recommended in Appendix A of Regulatory Guide 1.33. Rev 2. February 1978. Appendix A includes operating procedures for the chemical and volume control system and administrative procedures for relief ' turnover, procedural adherence, and authorities and responsibilities for safe operation. Operating Procedure No. 1-0250020. Boron Concentration Control - Normal Control, Rev. 35, step 8.5.14 required that operators monitor the water flow totalizer and close valve V2525 after the desired volume was added during a boron concentration dilution using the direct path to the charging pump suction. Administrative Procedure No. 0010120, Conduct of 03erations, Rev 79. Appendix D Crew Relief / Shift Turnover, required t1at, for short term watchstander relief, a turnover be conducted including: general watchstation status, off-normal conditions, and tests in progress. Administrative Procedure No. 0010120, Appendix M Procedural Compliance and Implementation, required that controlled procedures be implemented and complied with in accordance with the instructions provided in OI 5-PR/PSL-1. Procedure 01 5-PR/PSL-1 Preparation, Revision, Review / Approval of Procedures Rev 67 Section 5.13.2, stated that all 3rocedures shall be strictly adhered to and identified that Operating 3rocedure 1-0250020 was not considered " skill of the trade" and was not
'to be performed from memory without referring to the procedure.
Administrative Procedure No. 0010120, Appendix E. Notification of Operations Supervisor /FPL Management, required prompt verbal notification of the Operations Supervisor for unplanned reactivity changes. Contrary to the above:
- 1. On January 22, 1996, at approximately 2:30 a.m., Unit 1 operators failed to close valve V2525 after the desired volume was added during a boron concentration dilution using the direct path.to the charging pump. Operators had desired to add between 25 and 40 gallons of primary makeup water, but failed to stop the dilution until approximately 400 gallons were added. During this time, the temporary relief operator at the controls was unaware that a boron concentration dilution was in progress, which resulted in an unmonitored reactivity addition. The SRO and other operh6rs'in the control room were also unaware that a reactivity addition was in progress.
- 2. On January 22., 1996, at approximately 2:30 a.m., the Unit 1 operator at the controls conducted a short term watchstander relief with an inadequate turnover in that it failed to include gener61 watchstation status and coaditions including that a boron PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l 9 j concentration dilution was in progress. As a result, the relief l operator at the controls was unaware that a boron concentration dilution was in progress and failed to adequately monitor and control the dilution. , 1
- 3. On January 22, 1996, at approximately 2:30 a.m.. operators performed Operating Procedure 1-0250020 from memory, without !
referring to the procedure, and without strictly adhering to the
)rocedure. At the time, the procedure was written such that the
>oron concentration dilution that was performed could not have been performed by strictly adhering to the procedure.
- 4. On January 22, 1996, between 2:30 a.m. and 7:20 a.m., operators failed to give prompt verbal notification to the Operations Supervisor for unplanned reactivity changes that had occurred.
B. The Facility Operating License for St. Lucie Unit 1 authorizes the licensee to operate the facility at a steady state reactor core power level not in excess on 2700 megawatts thermal (MWt). TS 1.25 defines rated thermal power to be a total reactor core heat transfer rate to the reactor coolant of 2700 MWt. TS 1.33 defines thermal power to be the total reactor heat transfer rate to the reactor coolant. Contrary to the above, on January 22. 1996, between approximately 2:20 and 3:30 a.m., the reactor core thermal power level limit of 2700 MWt (100%) was exceeded. due to operator inattentiveness. 100% reactor power was exceeded for approximately 70 minutes. Also, 101% reactor power was exceeded for approximately 4 minutes and a peak reactor power of approximately 101.18% was reached. C. 10 CFR 50.59 allows the licensee to make changes to the procedures as described in the Safety Analysis Report (SAR), without prior Commission approval, unless the change involves, in part, an unreviewed safety question. A proposed change shall be deemed to involve an unreviewed safety question if, in part, the probability of occurrence of an accident important to safety previously evaluated in the SAR may be increased. The licensee shall maintain records of changes in procedures made pursuant to this section, to the extent that they constitute changes in procedures as described in the SAR. These records must include a written safety evaluation which provides a basis for the determination that the change does not involve an unreviewed safety question. Contrary to the above, on January 23. 1996, the licensee made a change in Unit 1 procedures as described in the SAR and the records for that change did not include a written safety evaluation. Temporary Change 1-96-017 to procedure 1-0250020, Baron Concentration Control - Normal Operation, Rev. 35, added instructions for dilution in manual and directly to the suction of the c arging pumps. However, the SAR, paragraph 15.2.4.1. states that .oron dihtion is conducted under strict administrative procedures which simit the rate and magnitude of any required change in boron concentration. Further, the SAR states that boron dilution must be conducted in automatic (such that when the PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
10 specific amount has been injected. the demineralized water control valve l 1s shut automatically) and describes introduction into the volume control tank (VCT). The SAR concludes that, in part because of the procedures involved, the probability of a sustained or erroneous dilution is very low. The licensee implemented Temporary Change 1 017 on January 23,1996. .without a written safety evaluation. i General Descriotion of the Event I At approximately 0225 on January 22. 1996, the Unit 1 control board Reactor . Controls Operator (RCO) began a manual dilution to the RCS by aligning primary makeup water (demineralized water) directly to the suction of the 18 Charging Pump. Moments after beginning the dilution, the board RC0 responded to a secondary plant annunciator and then saw the desk RC0 return from the kitchen. He requested that the desk RCO relieve him so that he could prepare his lunch. During the turnover, there was no discussion of the dilution in progress. Following the turnover, the relief o)erator at the controls and the Nuclear Plant Supervisor (NPS). who was at t1e desk RCO station, were not aware that a dilution was in progress. The original board RC0 returned between 5-10 minutes later and immediately recognized his error. He informed the other RC0 of the overdilution, which was overheard by the NPS, and stopped the dilution. ' The NPS directed the ANPS take charge and begin a manual boration. Unit 1 I entered 2-hour TS LCO Action Statement 3.2.5 for Tc greater than 549 F. The maximum cT obtained was 549.9 F and the maximum reactor power was 101.18%. Tc was above the TS limit of 549 F for approximately 50 minutes and reactor power was above 100% for approximately 70 minutes. The TS LC0 Action Statement for
- Tc was not exceeded and the guidance of the Jordan memorandum on maximum reactor power was not exceeded. The operators did not verbally notify plant management or the NRC of this event.
Detailed Seauence of Events (Note that the times for the se relevant e"?nts are mentioned) quence of events are approximate and only 1/21/96 11:00 p.m. Incoming mid shift assumed Unit I responsibility with the Unit at 100% power. 870 MWe Tavg at 575 degrees F. Thot at 600 degrees F. Tcold at 548.9 degrees F. RCS Boron concentration at 376 worth at -2722 pcm, all CEAs fully withdrawn and manual, andppm, no Xe Technical Specification action statements in effect. Major evolution planned for the shift was to place the waste gas system in service. Further, there was an annunciator alarm E-9 associated with circulating water pump lube water supply strainer delta P high that was intermittently coming in due to a failed pressure switch. 11:45 p.m. Board RC0 reset to zero the primary water (to VCT or charging pump) flow totalizer in preparation for inventory balance (RCS PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
I 11 leak rate calculation) 11:00 p.m.- 2:00 a.m The board RC0 recalled performing at least two dilutions of approximately 35 gallons each between 11:00 p.m. and 2:20 a.m. without resetting the totalizer. 1/22/96 xx:xx a.m NPS arrived in Unit I control room to gather data for morning report meeting and sat near desk behind control boards. STA was also present near NPS xx:xx a.m. ANPS turned over control room senior reactor operator responsibility to NPS and proceeded to the kitchen to prepare breakfast xx:xx a.m. Desk RC0 left control room to go to the kitchen 2:20 a.m. Normal continued fuei burnup resulted in indicated Tc of 548.7 degrees F on RTGB-104 (digital meter). At this point the board RCO decided to restore Tc to maximum allowable program value of 549.0 degrees F. xx:xx a.m. Desk RCO arrived in the control room with his meal 2:25 a.m. The board operator began a manual dilution by aligning primary water to the suction of the charging pumps by opening FCV-2210X and A0V-2525. The flow rate was approximately 44 gpm. 2:26 a.m. Annunciator E-9 associated with circulating water lube water supply strainer high delta P was received. The board RCO walked to the panel and acknowledged the annunciator. 2:27 a.m. After acknowledging the annunciator. the board operator decided' to proceed to the kitchen to prepare his meal. The board operator conveyed this to the desk o>erator and requested that he take over the board operator responsi3111 ties. However, he did not mention the ongoing dilution. The desk operator got up and proceed to the board in the vicinity of panel 103. The original board operator proceeded to the kitchen and started preparing his meal on a skillet that had been kept warm. At this time the NPS and the STA were in the control room at the desk area. The NWE had been in and out of the control room throughout the shift. The relief operator at the controls. NPS. STA, and NWE were not aware of the ongoing dilution. 2:35 a.m. The original board operator returned from the kitchen with his meal. Upon approaching the board, he realized that he had left the control room with an ongoing manual dilution. He exclaimed that he had overdiluted and immediately began securing the dilution. The desk operator questioned how much water was added and the board operator noted from the totalizer that approximately PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
12 400 gallons was added. 2:35 a.m. Soon after, annunciator M-16 associated with RCP controlled bleedoff pressure high was received. At this point the Tc was noted by the desk operator to be 549.6 degrees F. Entry into two hour action statement associated with Technical Specification 3.2.5. DNB paramenters was recognized and later logged. 2:36 a.m. The desk operator directed the board operator to initiate boration to restore Tc to 3rogram. The NWE calculated the amount of borated water to ]e added to the RCS. The NPS asked the desk operator to notify the unit ANPS to come to the control room. x:xx a.m. ANPS walked into the control room. 2:41 a.m. Tc reached the highest noted value of 549.9 degrees F. MWe reached 875 and indicated reactor power was approximately 101.2% x:xx a.m. Operator secured boration. 3:14 a.m. Tc noted below 549.0 degrees F. Technical Specification action statement was exited. x:xx a.m. STA initiated an In-House Event Report and notified HPES personnel by telephone. 5:45 a.m.- 6:00 a.m. . Shift turnover occurred. It appears that the dilution event was not discussed with the oncoming shift. 6:25 a.m. In-House Event Report was E-mailed to standard distribution, which included plant management, by the STA. 6:30 a.m. The Operations Manager toured the control room but was not informed of the over dilution event.- 7:20 a.m. The Operations Manager read the control room logs (in his office by computer) and questioned the log entry associated with the overdilution event. 7:30 a.m. Licensee initiated a detailed investigation associated with the event. 7:45 a.m. Senior Plant management was notified of the event during the morning meeting. 10:00 a.m. NRC resident inspector was given the event report that was initiated associated with the event. PR^ POSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
13 ST. LUCIE ONSITE EVENT FOLLOWUP INSPECTION OVERDILUTION EVENT of 1/22/96 (Exit was at 10:00 a.m. on 1/30/96) Inspectors: R. Schin S. Sandin B. Desai Summary of draft oreliminary findinas:
- 1. Magnitude of power and temperature excursion
- a. Reactor power Peak reactor power was approximately 101.18%
100% power was exceeded for approximately 70 minutes 101% power was exceeded for approximately 4 minutes
- The event was within the accident analysis
- The guidelines of the Jordan memo were not exceeded
- b. Cold leg temperature Peak Tc was approximately 549.9 degrees F
- TS limit of 549 was exceeded for approximately 50 minutes TS 2-hr. action statement was properly entered and was not exceeded
- 2. Concern with operator attentiveness - Potential / Apparent VIO of procedures (Enforcement panel form completed on this issue):
- a. Operators failed to stop dilution when the proper amount had been added,
- b. There was inadequate watch turnover for the operator at the controls during dilution,
- c. Operators failed to follow the Conduct of Operations procedure in performing the dilution procedure.
- d. Operators failed to adequately report the event to licensee management.
- 3. Concern with control room command and control - Weakness
- a. The SR0 in the control room was not aware of the dilution in progress,
- b. The board operator did not inform the SR0 of dilution - this was a general practice at the site and not required by procedures.
- c. The watchstander board was not maintained (on Saturday).
- d. The SRO in the control room was allowed to be in the ANPS office for unlimited time, out of sight of control room activities and out of hearing range of almost all control room activities except l annunciator alarms (not applicable during this event). ;
1 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
4 14 :
- 4. Weaknesses in procedures
- a. The Unit 2 dilution procedure had been changed, but not the Unit 1 procedure, to more accurately describe dilution the way the o)erators had performed it for years (in manual and direct to the clarging Jumps). During the event, manual dilution could not be accomplis 1ed by using the Unit 1 procedure in compliance with the Conduct of Operations.
- b. Procedures and practices for dilution (before and during the ,
event) did not support the FSAR accident analysis assumptions on how dilution was performed. The FSAR assumed dilution in automatic and to the VCT.
- c. Procedures for dilution (before and during the event) did not require ~the operator at the controls to remain by the dilution controls and to closely monitor the dilution during a manual dilution with no automatic shutoff.
- 5. Weaknesses in corrective action
- a. Potential VIO of 10 CFR 50.59: Revised procedure (after the event) did not support the FSAR Ch mter 15 accident analysis assumptions on how dilution was pern "med. The FSAR assumed dilution in. automatic and to the VCT.
- b. The revised procedure for manual dilution (after the event) did not require the operator at the controls to remain by the dilution controls and to closely monitor the dilution during a manual ,
dilution with no automatic shutoff. l
- c. The licensee initial investigation of the event was not thorough l in that it concluded that maximum reactor power was 100.2%.
Subsequent review by the NRC and licensee found that maximum reactor power was approximately 101.18%. l l
- 6. Weakness in Operational Experience Feedback i
- a. In response to SOER 94-02. dated September 1994, which described a i similar Turkey Point overdilution event and several inadvertent '
dilution events at other utilities, the licensee reviewed the St. i I Lucie operating procedures related to dilution and concluded that no changes were needed. This was a missed o]portunity to strengthen operating procedures to prevent t1e 1/22/96 overdilution event.
- 7. Other comments
- a. There was no clearly noticeable indication of dilution in progress. The dilution clicker was quiet (might not be heard from i the desk area) and sounded identical to the nearby clickers that routinely made noise.
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR, OE
15
- b. Operators routinely did not log reactivity additions; however, the licensee's Conduct of 0)erations procedure stated that operators should log reactivity c1anges.
LICENSEE DISSENTING COMMENTS
- 1. The licensee had dissenting comments on item 5.a. above. the potential violation of 10 CFR 50.59. The inspectors told the licensee at the exit that those dissenting comments would be included in the inspection report, for further review by NRC management. The dissenting comments, from the engineering manager (Dan Denver) and the licensing manager (Ed Weinkam), included:
- a. The previous procedure allowed diluting in manual and directly to the suction of the charging pumps, and that had been the practice for many years. Therefore, the temporary change on 1/23/96 (after the event) did not change the method of dilution, but only clarified a previously existing procedure and made it conform to
" verbatim compliance" rules. The inspectors did not disagree. In fact, further review, as requested by the inspectors, found that the first time the dilution ]rocedure was changed to allow opening of valve 2525 (directly to t1e suction of the charging pumps) was in a change to rev. 2 of the procedure, in 1976, before the operating license was issued.
- b. The design of the plant (piping, valves) always was such that dilution in manual and directly to the suction of the charging pumps was possible. The inspectors did not disagree.
- c. The accident analysis assumed a worst case dilution event with demineralized water going directly to the suction of the charging pumps and three charging pumps running. That would be three times the flowrate of this event and therefore that analysis bounds this event. The inspectors did not disagree,
- d. The FSAR Chapter 9 description of the Chemical and Volume Control System did not prohibit dilution in manual and directly to the suction of the charging pumps. The inspectors did not disagree.
- e. The automatic mode of dilution is less safe than the manual mode, in that there is more opportunity for a malfunction that could result in a maximum flowrate ap) roaching the design limit. The inspectors did not comment on tlat position.
- f. The procedure change that first allowed dilution directly to the suction of the charging pumps was made before the operating license was issued, therefore 10 CFR 50.59 did not apply to that change. The inspectors did not comment on that position.
- g. Since the operating procedure that was in effect at the time the operating license was issued allowed dilution in manual and directly to the suction of the charging pumps, that method was PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
( ) H2 l l included in the original licensing basis of the plant. The I inspectors did not agree with that position. l
- h. After receiving these licensee comments, the inspectors' concern l remained unchanged: The Temporary Change of 1/23/96 (after the !
event) described procedure steps for dilution in manual and i directly to the suction of the charging Jumas. That procedure was different from the one described in the :SAR. The licensee's procedure differed from the FSAR in that it allowed a faster rate of reactivity addition and without an automatic shutoff. The l licensee had not performed a safety analysis of this difference l and had not revised the procedure and/or FSAR to make them agree. ;
- 2. The licensee also had a dissenting comment on item 5.c. above, the l weakness in.the licensee *s initial investigation. The dissenting comment, from the Plant Manager (Jim Scarola), was:
l
- a. The initial investigation, for the In-House Event Summary, was !
done by the STA. Timeliness was more important than quality at that time. Subsequent more thorough review would be performed by , the licensee. The inspectors acknowledged the licensee's comment. { 1 I l I l 4 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
1Z Proposed Operator NOTICE OF VIOLATION Docket No. 55-License No.0P-EA(s) TBD During an NRC inspection conducted on January 26-30, 1996, violations of NRC requirements were identified. In accordance with the " General Statement of. Policy and Procedure for NRC Enforcement Actions," NUREG-1600, the violations are listed below: Technical Specification 6.8.1.a required that written procedures be established, implemented, and maintained covering the activities recomended in Appendix A of Regulatory Guide 1.33. Rev 2. February 1978. Appendix A includes operating procedures for the chemical and volume control system and administrative procedures for relief turnover, procedural adherence, and authorities and responsibilities for safe operation. Operating Procedure No. 1-0250020. Boron Concentration Control - Nornial Control, Rev. 35, step 8.5.14 required that operators monitor the water flow totalizer and close valve V2525 after the desired volume was added during a boron concentration dilution using the direct path to the charging pump suction. Administrative Procedure No. 0010120. Conduct of 0)erations. Rev 79. Appendix D. Crew Relief / Shift Turnover, required tlat, for short term watchstander relief. a turnover be conducted including: general watchstation status, off-normal conditions, and tests in progress. Administrative Procedure No. 0010120, Appendix M. Procedural Compliance and Implementation, required that controlled procedures be implemented and complied with in accordance with the instructions provided in 015-PR/PSL-1. Preparation, Revision. Review / Approval of Procedures. Rev 67. Procedure 01 5-PR/PSL-1 Section 5.13.2, stated that all procedures shall be strictly adhered to and specifically identified that Operating Procedure 1-0250020 was not considered " skill of the trade" and was not to be performed from memory without referring to the procedure. Contrary to the above:
- 1. On January 22, 1996, at approximately 2:30 a.m., the Unit 1 operator failed to close valve V2525 after the desired volume was 4
added during a boron concentration dilution using the direct path to the charging pump. The o)erator had desired to add between 25 and 40 gallons of primary maceup water. but failed to stop the dilution until approximately 400 gallons were added. During this time, the temporary relief operator at the controls was unaware that a boron concentration dilution was in progress, which resulted in an unmonitored reactivity addition. The SR0 and other operators in the control room were also unaware that a reactivity addition was in progress. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
.o .
- i 16
- 2. On January 22. 1996, at approximately 2:30 a.m. the Unit 1 ,
operator at the controls conducted a short term watchstander i relief with an inadequate turnover in that he failed to include l general watchstation status and conditions including that a boron I concentration dilution was in progress. As a result, the relief ! operator at the controls was unaware that a boron concentration ! dilution was in progress and failed to adequately monitor' and I control the dilution. !
- 3. On January 22. 1996, at approximately 2:30 a.m.. the Unit 1 operator performed Operating Procedure 1-0250020 from memory, i without referring to the procedure, and without strictly adhering I to the procedure. At the time, the procedure was written such I that the boron dilution that was performed could not have been l performed by strictly adhering to the procedure. ,
These violations represent a Severity 8.evel III problem (Supplement ) l l l i j i I PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
d i. l l August 30, 1996 MEMORANDUM T0: James Lieberman Director . Office of Enforcement Stewart D. Ebneter. Regional Administrator /s/ L. A. Reyes i l FROM:
SUBJECT:
EA 96-236 AND 96-249: FLORIDA POWER AND LIGHT COMPANY. ST. LUCIE NUCLEAR PLANT - NOTICE OF VIOLATION AND PROPOSED . l IMPOSITION OF CIVIL PENALTY (Special Inspection Report ' Nos. 50-335/96-12 and 50-389/96-12) l Attached for your review and concurrence is the proposed enforcement action l for the subject case. Although this case meets the criteria for issuance as a ; i Regional action. it is being provided to you for formal review as a result of an agreement during the Jost conference caucus and the caucus consensus that . the severity of the 10 C:R 50.59 violation be reviewed and reaffirmed. The . issues discussed herein were identified during an inspection completed on July 12. 1996. ; As discussed in detail in the proposed enforcement action, we propose that a Notice of Violation (Notice) be issued to the licensee comprised of a Severity Level III violation and two Severity Level IV violations. The Severity Level III violation related to the licensee's failure to obtain Commission approval prior to implementing a change to the Emergency Diesel Generator (EDG) Fuel Oil Transfer System which was determined to involve an unreviewed safety question. The Severity Level IV violations involved four instances where the licensee failed to incorporate facility changes'into annunciator response procedures or plant drawings. In addition, a non-cited violation is proposed for one of the configuration management violations which was licensee identified and promptly corrected. A closed, predecisional enforcement conference was conducted with the licensee on August 19, 1996. At the conference, the licensee admitted the violations associated with configuration management as well as one examale of the 10 CFR 50.59 violation (setpoint issue). However, for the t1ree remaining examples of the 10 CFR 50.59 violation (temporary fire pump control element drive control system enclosure, and isolation of EDG fuel oil line valve) the licensee stated that 10 CFR 50.59 did not apply or the NRC was employing a position contrary to standard industry practice. On August 19 and 22. 1996, enforcement caucuses were conducted between Region II and the Office of Enforcement. It was determineti that the 10 CFR 50.59 violation regarding the EDG Fuel Oil Transfer system constituted an unreviewed safety question and met the criteria for a Severity Level III violation. Application of the civil penalty assessment process resulted in a base civil penalty because the license had previous escalated enforcement action, the violation was identified by NRC, and corrective actions were appropriate. The remaining three_ examples of the 10 CFR 50.59 violations were determined.not to be valid examples. In addition, the configuration management violations were recharacterized into two Severity Level IV 4
1 a j b 1 violations and a non-cited violation. The draft letter and Notice to the licensee are attached and are consistent with this agreed upon approach. ) In reviewing the proposed violation in Part I of the draft Notice, you should , be aware that there were discussions between the licensee and NRC at the time ; the licensee implemented the valve position change in question. Speci fically, on July 7. 1995, the day following completion of the licensee's 10 CFR 50.59 evaluation, a conference call was conducted between the licensee. Region II (K. Landis and M. Miller), and the Office of Nuclear Reactor Regulation (J. Norris). During this telephone call, the licensee discussed their plans to reposition the valve, their safety evaluation. their planned additional administrative controls, and the environmer.tal benefits of the change. Based on the recollection of several of the NRC participants in this call, it is not unreasonable that the licensee believed that there was a mutual understanding of the minimal safety significance of the change. given the specified compensatory measures, and that reasonable actions were being taken to both maintain the EDG operable while precluding an adverse environmental impact. This discussion was mentioned by the licensee at the conference: however, they did not provide any view as to the impact this discussion had on their failure to perform an adeauate 10 CFR 50.59 evaluation. There are views among the staff that based on NRC knowledge and involvement in this matter, the safety significance of the violation, and the age of the violation (prior to increased NRC sensitivity to the UFSAR and 10 CFR 50.59) that mitigation of the civil penalty or severity level would be appropriate. No additional reference materials are being provided to with this submittal as all inforn cion was previously provided to you in preparation for the initial enforcement panel and conference. This action is not exempt from the Office of Enforcement's timeliness requirements.
Attachment:
Draft Letter and Notice cc w/ attachment: R. Zimmerman. NRR J. Goldberg OGC THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRTCTOR, OE
W sa UNITED STATES 8 a ma%q'o NUCLEAR REGULATORY COMMISSION [' S REGION 11 4 o 101 MARIETTA STREET, N.W.. SUITE 2000 ( j ATLANTA, GEORGIA 303234199
%...../
EA 96-236 and EA 96-249 Florida Power & Light Company [ ATTN: T. F. Plunkett President - Nuclear Division P. O. Box 14000 Juno Beach. FL 33408-0420
SUBJECT:
N0TICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY -
$50.000 (NRC Special Inspection Report Nos. 50-335 and 50-389/96-12)
Dear Mr. Plunkett:
This refers to the inspection completed on July 12. 1996. at your St. Lucie facility. The inspection included a review of selected aspects of your configuration management and 10 CFR 50.59 safety evaluation programs. The results of our inspection were sent to you by letter dated July 26. 1996. A closed, predecisional enforcement conference was conaucted in the Region II office on August 19. 1996, with you and members of your staff to discuss the apparent violations, the .oot causes, and your corrective actions to preclude . recurrence. A letter summarizing the conference was sent to you by letter 1 dated ------ . Based on the information developed during the inspection and the information ) you provided during the conference the NRC has determined that violations of l NRC requirements occurred. The violations are cited in the enclosed Notice of ! Violation (Notice) and the circumstances surrounding them are described in ! detail in the subject inspection report. The violation in Part I of the Notice involves your failure to recognize an unreviewed safety question related to the implementation of a valve lineup change to the Emergency Diesel Generator (EDG) fuel oil transfer system. l Specifically, in July 1995, the licensee implemented a change to the 2B EDG I system to permit closing of a manual isolation valve from the Diesel Fuel Oil l Storage Tank to the day tanks in order to minimize in ground fuel oil leakage between the two tanks. As part of the change. the licensee instituted administrative measures including dedication of a non-licensed operator anc procedural revisions to assure timely opening of the valve following an EDG start. Although a safety evaluation was performed which concluded that a six percent increase in the probability of loss of the 2B3 emergency buss resulted from the change. it erroneously concluded that no increase in the probability of a component failure was created. The NRC has concluded that two new failure modes were introduced by the change: potential failure of the 9 THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
g j 4 FPL 2 l operator to unisolate the fuel oil line and failure of the manual isolation valve to open. Therefore, both the possibility for a malfunction of a type different than any evaluated previously in the UFSAR was introduced, and the i probability of a failure of a component important to safety was increased. representing a valid unreviewed safety question. At the conference, you stated that a safety evaluation was prepared for this change consistent with Florida Power and Light Company procedures and industry guidance (NSAC-25). However NRC's position with respect to an " increase in probability" differs. Although the NRC recognizes that the increase in probability oi component failure was small, a normally passive component was made active and an absolute increase in probability was realized. Notwithstanding the small probability increase, the violation in Part I of the Notice is of significant regulatory concern because a change was made to the EDG system resulting in the emergence of an unreviewed safety question for which a license amendment and NRC approval was not sought. Further, such failures to com31y with the requirements of 10 CFR 50.59 resulted in facility operations whica depart from the licensing and or design bases described in the Updated Final Safety Analysis Report (USFAR). Therefore, the violation in Part'I of the Notice is classified in accordance with the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy). NUREG-1600, as a Severity Level III violation. In accordance with the Enforcement Policy, a base civil penalty in the amount of $50.000 is considered for a Severity Level III violation. Because your facility has been the subject of escalated enforcement actions within the last 2 years', the NRC considered whether credit was warranted for Identf fication and Corrective Action in accordance with the civil penalty assessment process described in Section VI.B.2 of the Enforcement Policy. In this case, the NRC concluded that it is not appropriate to give credit for Identification because the violation was discovered by the NRC. With recard to consideration for Correct 7ve Action. at the conference you stated that your actions related to the violation in Part I of the Notice included revision of engineering safety evaluation guidance to clarify the definition of an increase in probability and issuance of a technical alert to all engineers regarding this issue. ' Further, although not directly related to this violation, additional emphasis has been placed on the importance of 10 CFR 50.59 and the UFSAR. Your recent actions in this regard include: (1) 10 CFR 50.59 reviewer certification: (2) additional 10 CFR 50.59 training for designated staff: (3) 10 CFR 50.59 procedural enhancements, and (4) implementation of the UFSAR Review Project. I A severity Level 111 problem and proposed civil penalty of $50,000 were issued on March 28. 1996 (EA 96 040) related to a dilution event. A severity Level Ill violation and proposed civil penalty were issued on November 13,1995 (EA 95-180) related to inoperable power
' operated relief valves, r l
TH18 DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE i s
I r o l FPL 3 . , Based on the above the NRC determined that credit was warranted.for
' Corrective Actfon, resulting in the base civil penalty.
Therefore, to emphasize the importance of performing safety evaluations for facility changes affecting safety and of prompt identification of violations and in consideration of your previous escalated enforcement actions. I have been authorized, after consultation with the Director. Office of Enforcement, to issue the enclosed Notice of Violation and Proposed Imposition of Civil > Penalty (Notice) in the base amount of $50.000 for this Severity Level III violation.
' Violations A and B described in Part II of the Notice have been categorized at Severity Level IV. The violations involve four instances where you failed to effectively incorporate design changes into plant operating procedures or '
drawings. These violations were NRC identified and are of concern because of the potential for misleading operators and the similarity of the violations to annunciator resaonse procedure deficiencies identified during previous ; inspections. T1e fifth apparent example of the configuration management , violation discussed at the conference involved your failure to properly i incorporate the spent fuel pool heat load calculation into operational procedure limitations prior to initiating core off-load. For this issue, the NRC has decided to exercise discretion and characterize the violation as non-cited (NCV 50-335/96-12-01) in accordance with Section VII.B.1 of the Enforcement Policy. Specifically, you identified the violation and promptly instituted appropriate corrective action. I NRC has concluded that no violation occurred with respect to the three
- . additional apparent failures to comply with 10 CFR 50.59 addressed in the subject inspection report and discussed at the conference. Specifically.
(1) the Unit 2 Control Element Drive Mechanism Control System Enclosure was ' 4
.not required to be included in the UFSAR, and installation and subsequent modifications did not require 10 CFR 50.59 safety evaluations: (2) the configuration of a temporary fire pump placed in stand-by during the 1996 Ur.it I refueling outage did not require a 10 CFR 50.59 evaluation in that the configuration was as described in the UFSAR (i.e.. the discharge valve was '
- closed and the pump was isolated from the system)
- (3) the failure to perform
- a 10 CFR 50.59 safety evaluation to charle the setpoints and procedures for ;
operat1ng the fuel hoist was identified end corrected by you prior to actual fuel movement. This letter closes any further NRC action on these matters. You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response. In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requ1rements. THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
4 FPL 4 . In accordance with'10 CFR 2.790 of the NRC's " Rules of Practice l" a copy of this letter. its enclosure, and your response will be placed in the NRC Public : Document Room (PDR). To-the extent possible, your response should not include ' - any personal privacy. proprietary, or safeguards information so that it can be placed in the PDR without redaction. Sincerely. i Stewart D. Ebneter . ' Regional Administrator !
- Docket Nos. 50-335. 50-389 License Nos. DPR-67. NPF-16 .
4
Enclosure:
Notice of Violations and Proposed ' Imposition of Civil Penalty cc w/ encl: J. A. Stall Site Vice President St. Lucie Nuclear Plant 4 P. O. Box 128 : Ft. Pierce. FL 34954-0128 H. N. Paduano. Manager Licensing and Special Programs Florida Power and Light Company , P. O. Box 14000 Juno Beach. FL 33408-0420 i J. Scarola Plant General Manager i St. Lucie Nuclear Plant l P. O. Box 128 1 Ft. Pierce. FL 34954-0128 l 1 E. J. Weinkam i Plant Licensing Manager St. Lucie Nuclear Plant l i P. O. Box 128 I Ft. Pierce. FL 34954-0218 cc w/ encl: (Cont'd on Page 5) THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLIC ] oesCtosURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i
FPL 5 , cc w/enci (Cont'd): J. R. Newman. Esq. Morgan Lewis & Bockius ' 1800 M Street. NW Washington D. C. 20036 John T. Butler. Esq. ' Steel. Hector and Davis 4000' Southeast Financial Center Miami. FL 33131-2398 Bill Passetti Office of Radiation Control Department of Health and Rehabilitative Services 1317 Winewood Boulevard Tallahassee, FL 32399-0700 i l Jack Shreve. Public Counsel Office of the Public Counsel c/o The Florida Legislature 1
-111 West Madison Avenue. Room 812 Tallahassee. FL 32399-1400 Joe Myers, Director Division of Emergency Preparedness Cepartment of Community Affairs 2740 Centerview Drive Tallahassee. FL 32399-2100 Thomas R. L. Kindred County Administrator St. Lucie County 2300 Virginia Avenue Ft. Pierce. FL 24982 ;
Charles B. Brinkman Washington Nuclear Operations ABB Combustion Engineering. Inc. 12300 Twinbrook Parkway. Suite 3300 Rockville. MD 20852 THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUSLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DMECTOR. OE
i r s d ) i FPL' -6 , 4 31stribution'w/enci: e MJBLIC -
.EJulian. SECY !
BKeeling, CA; (
'JTaylor. E00
'JMilhoan, DEDR t
RZimmerman. NRR
'SEbneter, RII LChandler, OGC-JGoldberg, 0GC JLieberman, OE Enforcement Coordinators RI, RIII. RIV- l EHayden, OPA !
EJordan, AEOD ' PRabideau. OC- , DDandois. OC GCaputo. OI HBell, OIG : i
.0E:EA File. (B. Summers. OE) (2 letterhead)
MSatorius, OE AGibson.-RII JJohnson. RII CEvans, RII Buryc.-RII- , KClark. RII
.RTrojanowski, RII ;
CCasto, RII Klandis. RII r JNorris, NRR ABoland, RII NRC Resident Inspector ' U.S. Nuclear Regulatory Comm. 7585 South Highway A1A Jensen Beach, FL- 34957-2010
'END TO #UBLIC 00CtMENT 4 W *ts NO '
0FFICE o!!-ORP RI! DR5 Rlt [tC5d8' 811 ORA RIY 004 StrAATURE I I AGibson w yre C[ vans LReyes , NAME JJohnsbn DATE CB / 8 06 - 08 / ' 96 08 / '% CS / / % 08 e 'M YES NO VE5 NO VES NO VE5 NO VE5 NO COPY? OFFICIAL RECORD COPY DOCUMIENT NAME: H:\l960 PEN.ENFs96236STL.DIR\PKGT00E . i i THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUSLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE 6 4 [ t
4 e NOTICE O 10LATION k[ PROPOSED IMPOSITION OF CIVIL PENALTY Florida Power and Light Company Docket Nos. 50-335. 50-389 St. Lucie Nuclear Plant License Nos. DPR-67. NPF-16 EA 96-236 and 96-249- t As a result of an NRC inspection completed on July 12.' 1996. violations of NRC requirements were identified. In accordance with the " General' Statement of Palicy and Procedures for NRC Enforcement Actions" (Enforcement P0licy). NUREG-1600. the Nuclear Regulatory Commission preposes to impose a civil
, penalty pursuant to Section 234 of the Atomic Energy Act of 1954. as amended ,
(Act). 42 U.S C. 2282, ant 10 CFR 2.205. The particular violations and associated civil penilty are set forth below: I. Violations Assessed 6 Civil Penalty 10 CFR'50.59. " Changes. Tests and Experiments." provides, in part, that the licensee Pay make .;hanges in the facility as described in the safety
- analysis report-(SAR) without orior Commission approval unless the proposed change invol_ves an unreviewed safety question. A proposed change shall be deemed to involve an unreviewed safety question if the probability of occurrence of a malfunction of equipment important to i safety previously evaluated in the SAR may be increased, if a
, possibility for an accident or malfunction of a different type than any evaluated previously in the SAR may be created, or if the margin of safety as defined in the basis for any technical specification is reduced. Contrary to he above. in July 2995, the licensee rade a change to the facility which involved 60 unreviewed safety question without prior Commission approval. Specifically, the 2B Emergency Diesel Generator (EOG) fuel oil line was manually 1solated to secure a through-wall fuel
. oil I2ak. In taking this action the licensee introduced two new failure modes for the 2B EDG.'.snich botn increased the probability of occurrence of a malfunction of the EDG above that previously evaluated
)
in the SAR and the possileility for malfunction of a different type than any evaluated previously in the SAR. resulting in an unreviewed safety question. ;01013) This is a Severity Level III violation (Supplement I) Cid i Penalty - $50,000 II. Violations Not' Assessed a Civil Penaltv 10 CFR 50. Appendix B. " Quality Assurance Criteria for Nuclear Power
- . Pints and Fuel Reprocessing Plants." Criterion III requires, in part.
that measures be establ kned to assure that applicable regulatory requirementc and the design Dasis for safety-related structures. THIS DOCUMENT CONTAINS PREDECislONAL INFORMATlON NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPftOVAL OF THE DIRECTOR, OE
i n Notice-of Violation and Proposed 2 1 Imposition of Civil Penalty systems. and components are correctly translated into specifications, drawings, procedures, and instructions. Florida Power and Light Company Topical Quality Assurance Report. TOR 3.0. Revision.11 implements these requirements.. Section 3.2.
" Design Change Control." provides. in part, that design changes shall be reviewed to ensure that implementation of the design changes is coordinated with any necessary changes to operating procedures. In addition. Section 3.2.4. " Design Verification." provides, in part. that design control measures shall be established to independently verify the design inputs, design process. and that the design inputs are correctly incorporated into the design output. .
A. Contrary to the above, the licensee failed to coordinate design changes with the necessary changes to operating procedures as follows:
- 1. Plant Change / Modification (PC/M) 109-294 Setpoint Change to the Hydrazine Low Level Alarm (LIS-07-9), was completed on January 6.1995. without assuring that affected Procedure ON0P 2-0030121. Plant Annunciator Summary, was revised.
This resulted in annunciator S-10. HYDRAZINE TK LEVEL LO. showing an incorrect setpoint of 35.5 inches in the procedure.
- 2. PC/M 268-292. Intake Cooling Water Lube Water Piping Removal and Circulatory Water Lube Water Piping Renovation, was completed on~ February 14. 1994. without assuring that affected Procedure ONOP 2-0020131. Plant Annunciator Summary, was revised. This resulted in the instructions for annunciator E-16. CIRC WTR PP LUBE SPLY BACKUP'IN SERVICE.
incorrectly requiring operators to verify the position of valves MV 21-4A and 48 following a safety injection actuation system signal to ensure they were deenergized and had no control room position indication.
- 3. PC/M 275-290. Flow Indicator / Switch Low Flow Alarm and Manual Annunciator Deletions, was completed on October 28.
1992, without assuring that affected Procedure ONOP 2-0030131. Plant Annunciator Summary, was revised. This resulted in the instructions for safety-related annunciators LA-12. ATM STM DUMP MV-08-18A/18B OVERLOAD /SS ISOL. and LB-12. ATM STM DMP MV-08-19A/19B OVERLOAD /SS ISOL. incorrectly requiring operators to check Auto / Manual switch i or switches for the manual position. (02014) This is a Severity Level IV violation (Supplement I) P THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLic DISCLOSUME WITHOUT THE APPROVAL OF THE DIRECTOR, OE , i
~
t. Notice of Violation and Proposed 3 Imposition of Civil Penalty B. Contrary to the above, the licensee failed to assure that the design of the Circulating and Intake Cooling Water System was correctly translated into plant drawings. Specifically, during implementation of PC/M 341-192. Intake Cooling Water Lube Water Piping Removal and Circulatory Water Lube Water Piping Renovation, the as-built Drawing No. JPN-241-192-008 was not incorporated into Drawing No. 8770-G-082. Flow Diagram Circulating and Intake Cooling Water System. Revision 11. Sheet 2. issued May 9. 1995. for PC/M 341-192. This resulted in Drawing No. 8770-G-082 erroneously showing valves 1-FCV-21-3A and 3B and associated-piping as still installed. (03014) This is a Severity Level IV violation (Supplement I). Pursuant to the provisions of 10 CFR 2.201. Florida Power and Light Company (Licensee) is hereby required to submit a written statement or explanation to l the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission. within 30 days of the date of this Notice of Violation and Proposed Imposition of Civil Penalty (Notice). This reply should be clearly marked as a " Reply to a Notice of Violation" and should include for each alleged violation: (1) admission or denial of the alleged violation. (2) the reasons for the violation if admitted, and if denied, the reasons why. (3) the corrective steps that have been taken and the results achieved. (4) the corrective steps l that will be taken to avoid further violations, and (5) the date when full l compliance will be achieved. If an adequate reply is not received within the l time specified in this Notice, an order or a Demand for Information may be issued as why the license should not be modified. suspended. or revoked or why such other action as may be proper should not be taken. Consideration may be given to extending the response time for good cause shown. Under the authority of Section 182 of the Act. 42 U.S.C. 2232. this response shall be submitted under oath or affirmation. Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalty by letter addressed to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission with a check. draft, money order, or electronic transfer payable to the Treasurer of the United States in the amount of the civil penalty proposed above, or the cumulative amount of the civil penalties if more than one civil penalty is proposed, or may protest imposition of the civil penalty in whole or in part. by a written answer addressed to the Director. Office of Enforcement. U.S. Nuclear Regulatory Commission. Should the Licensee fail to answer within the time specified, an order imposing the civil penalty will be issued. Should l the Licensee elect to file an answer in accordance with 10 CFR 2.205 I protesting the civil penalty, in whole or in part. such answer should be l clearly marked as an " Answer to a Notice of Violation" and may: (1) deny the violations listed in this Notice, in whole or in part. (2) demonstrate extenuating circumstances. (3) show error in this Notice, or (4) show other reasons why the penalty should not be imposed. In addition to protesting the THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
l Notice of Violation and Proposed 4 Imposition of Civil Penalty. civil penalty in whole or in part, such answer may request. remission or mitigation of the penalty. Any written answer in accordance with 10 CFR 2.205 should be set forth ) separately from the statement or explanation in reply pursuant to 10 CFR 2.201.- but may incorporate parts of the'10 CFR 2.201 reply by specific reference (e.g., citing page and paragraph numbers) to avoid repetition. The attention of the Licensee is directed to the other provisions of 10 CFR 2.205, regarding the procedure for imposing a civil: penalty. Upon failure to pay any civil penalty due which subsequently has been determined in accordance with the applicable provisions of 10 CFR 2.205, this matter may be referred to the Attorney General. and the penalty, unless compromised, remitted or mitigated, may be collected by civil action pursuant
' to Section 234c of the Act. 42 U.S.C. 2282c.
The response noted above (Reply to Notice of Violation, letter with payment of civil senalty, and Answer to a Notice of Violation) should be addressed to: James ieberman, Director. Office of Enforcement. U.S. Nuclear Regulatory Commission. One White Flint North. 11555 Rockville Pike. Rockville. MD 20852-2738, with a copy to the Regional Administrator. U.S. Nuclear Regulatory Commission. Region II and to the Resident Inspector at the St. Lucie facility. Because your response will be placed in the NRC Public Document Room (PDR). to i the extent possible, it should not include any personal privacy. 3roprietary, or safeguards information so that it can be placed in the PDR wit 1out redaction. However, if you find it necessary to include such information, you should clearly indicate the specific information that you desire not to be placed in the PDR. and provide the legal basis to support your request for withholding the information from the public. Dated at Atlanta. Georgia this ---- day of September 1996 THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
[ , , d vio'lations and a non-cited violation. The draft letter and Notice to the licensee are attached and are consistent with this agreed upon approach. In reviewing the proposed violation in Part I of the draft Notice, you should be aware that there were discussions between the licensee and NRC at the time the licensee implemented the valve position change in question. Specifically, on July 7, 1995 the day following completion of the licensee's 10 CFR 50.59 evaluation, a conference call was conducted between the licensee. Region II (K. Landis and M. Miller), and the Office of Nuclear Reactor Regulation (J. Norris). During this telephone call, the licensee discussed their plans to reposition the valve, their safety evaluation, their planned additional administrative controls, and the environmental benefits of the change. Based on the recollection of several of the NRC participants in this call. it is not unreasonable that the licensee believed that there was a mutual understanding of the minimal safety significance of the char.ge, given the specified compensatory measures, and that reasonable actions were being taken to both maintain the EDG operable while precluding an adverse environmental impact. This discussion was mentioned by the licensee at the conference; however, they did not provide any view as to the impact this discussion had on their failure to perform an adequate 10 CFR 50.59 evaluation. There are views among the staff that based on NRC knowledge and involvement in this matter, the safety significance of the violation, and the age of the violation (prior to increased NRC sensitivity to the UFSAR and 10 CFR 50.59) that mitigation of the civil penalty or severity level would be appropriate. No additional reference materials are being provided to with this submittal as all information was previously provided to you in preparation for the initial enforcement' panel and conference. This action is not exempt from the Office of Enforcement's timeliness requirements.
Attachment:
Draft Letter and Notice cc w/ attachment: R. Zimmerman. NRR l J. Goldberg. 0GC l tFND TO Ptml10 OmMNT Rom' VFs No // Off!CE R!! DRP D11 DRS RII:EIC$ RII:0RA . RI! h StGNATURE l JJohnson AGibson BUyrc CEvans ye NAME DATE 08 / / 96 C8 / 96 08 / / 96 08 / / 96 1/ h COPY 1 YES NO YES NO YES NO VES NO YES~ /NO / OFFICIAL RECORD COPY DOCUMENT NAME: H:\1960 PEN.ENF d6STL.DIR\PKGT00E
#see num muerw.e i
THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION . NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
two Severity Level IV violations and an non-cited violation. The draft letter and Notice to the licensee, provided as Attachment 1. are consistent with this agreed upon approach. In reviewing the proposed violation and civil penalty in Part I of the draft Notice, you should be aware that there were discussions bet' ween the licensee and NRC at the time the licensee implemented the valve position change in question. Specifically, on July 7.1995, the day following completion of the licensee's 10 CFR 50.59 evaluation, a conference call was conducted between and the Office of Nuclear the licensee. Reactor Region(J. Regulation II (K. Landis Norris). and M. During this Miller), telep hone call, the licensee discussed their plans to reposition the valve, their safety evaluation, their planned additional administrative controls, and the environmental benefits of the change. Based on the recollection of sev'eral of the NRC participants in this call, it is not unreasonable that theA icensee believed that there was a mutual understanding of the minimal safety significance of the change given the specified compensatory measures, and that reasonable actions were being taken to both maintain the EDG operable while precluding an adverse environmental impact. This discussion was mentioned by the licensee at the conference: however, they did not provide any view as to the impact this discussion had with their failure to perform an ' adequate 10 CFR 50.59 evaluation. .There are views among the staff that based on this NRC knowledge and involvement, the safety significance of the violation, and the age of the violation (prior to increased NRC sensitivity to the UFSAR and 10 CFR 50.59) that mitigation of the civil penalty or severity level would be appropriate. No additional reference materials are being provided to with this submittal as all information was previously provided to you in preparation for the initial enforcement panel and conference. This action is not exempt from the Office of Enforcement's timeliness requirements.
Attachment:
Draft Letter and Notice I cc w/ attachment: R. Zimmerman. NRR J. Goldberg OGC n
%FNO TO PUBtTC 00CtMFNT ROOM VE5 7 Nd 0FFICE RI,1;DRP R!l:QRS g ,
RII;tlp (!_1. ORA 3bil:0RA StGNATURE NAME JJ . AGibson B , CEv LReyes DATE 8/M/96 08 / /% p"h / 96 / 96 08 / / 96 COPY? 'Yf4 NO [/T[5' , NO ((YES) NO [5 NO YES NO OFFICIAL REs0RD COPY
- DOCUMdtt'NAME: If: \ l900 PEN . ENF \ 96236STL . DI R\ PKGT00E '
THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE l l l
.-.=.._ -
f~ NW ENFORCEMENT ACTION WORKSHEET
' dwu %
m mca..+ w.0 u ), (ST LUCIE OVERDILUTION EVENT) y_k4 PREPARED BY: R. Schin DATE: February 5, 1996 This Notice has been reviewed by the Branch Chief or Divis Director and each violation includes the appropriate level of sp f as to how and when the requirement was violated. M 1gnature Facility: St. Lucie Unit (s): 1 Docket Nos: 50-335 License Nos: DPR-67 Inspection Report No: 50-335,389/96-01 Inspection Dates: January 26-30, 1996 l Lead Inspector: R. Schin
- 1. Brief Summary of Inspection Findings:
Concern with operator attentiveness related to a reactivity addition ! event, and related operator violations of procedures: I
- a. Operators failed to stop dilution when the proper amount had been added.
- b. There was inadequate watch turnover for the operator at the ,
controls during dilution.
- c. Operators failed to follow the Conduct of Operations procedure .in performing the dilution procedure .(lack of strict / verbatim compliance).
- d. Operators failed to adequately report the event to licensee management.
Also, operators exceeded the steady state licensed power limit of 2700 megawatts thermal (100% power). In addition, the licensee nade a change to the procedures as described in the SAR without a 10 CFR 50.59 safety evaluation. See the attached draft NOV, General Description of Event, Detailed Sequence of Events, Summary of Draft Preliminary Inspection Findings, Control Room Diagram, CVCS Charging System Diagram, Procedures, and FSAR. b PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l 2 ,
- 2. Analysis of Root Cause:
Operator inattentiveness to reactivity addition. ]
- 3. Basis for Severity Level (Safety Significance): f
.I.C.3 Inattentiveness to duty on the part of licensee personnel, while adding reactivity to the reactor, and I.C.7 A breakdown. in the control of licensed ' activities' involving a number of violations that are related that collectively represent a significant lack of attention or carelessness toward licensed responsibilities. .
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
EA 95-180 (EEI 95-16-01); LTOP inoperability due to PORV failure Event date 8/9/95 ,
- 5. Identification Credit? No Identified through an event. The licensee initiated an In-House Event Report and gave a copy to the NRC resident inspector promptly after the event. -The event occurred at approximately 0220 on January 22, 1996.
Missed opportunities:
- a. In response to SOER 94-02, dated September 1994, which described a similar Turkey Point overdilution event and several inadvertent dilution events at other utilities, the licensee reviewed the St.
Lucie operating procedures related to dilution and concluded that no changes were needed. This'was a missed opportunity to strengthen operating procedures to prevent the 1/22/96 overdilution event.
- b. The Unit 2 dilution procedure had been changed in December 1995, 4 but not the Unit 1 procedure, to more accurately describe dilution the way the operators had performed it for years (in manual and direct to the charging pumps). During the event, manual dilution could not be accomplished'by using the Unit l' procedure in compliance with the Conduct of Operations (strict / verbatim compliance).
- 6. Corrective Action Credit? Yes The licensee initiated an In-House Event Report summarizing the event and began distribution of that report within about four hours after the event. The licensee also immediately removed the reactor operator who had initiated the~ event from licensed duties, promptly issued a Night Order and conducted training on the event with operators on each shift; J revised the Unit 1 procedure for dilution so that manual dilution could be performed by strict compliance to the procedure steps;' revised the Conduct of Operations procedure to require the RO to get prior approval PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT.THE APPROVAL OF THE DIRECTOR, OE .
I o - ig 3 . .from the SRO for dilution /boration, the SR0 to directly supervise dilution /boration, no RO or SRO turnover during dilution /boration, and RTGB walkdown prior to.R0 or SRO short term relief; and initiated
- further review of the event.
l l Weaknesses in the licensee's corrective actions included:
- a. Potential VIO of 10 CFR 50.59: The revised procedure (after the ;
event) did not support the FSAR Chapter 15 accident analysis assumptions on how dilution was performed. The revised procedure 1
; described dilution in manual (with no automatic shutoff) and directly to the suction of the charging pumps. The FSAR assumed 4
dilution in automatic (with an automatic shutoff) and to the VCT. !
, (where the demineralized water would six with boric acid solution before going to the suction of the charging pumps and result in a lower rate of reactivity addition). The licensee had not 4 performed a safety analysis of this difference and had not ri ' sed the procedure and/or FSAR to make them agree.
I b. The revised procedure for manual dilution (after the event) did not require the operator at the controls to remain by the dilution controls and to closely monitor the dilution during a manual dilution with no automatic shutoff. i i
- c. The licensee initial investigation of the event was not thorough !
. in that it concluded that maximum reactor power was 100.2%. l
. Subsequent review by the NRC and licensee found that maximum l 4
reactor power was approximately 101.18%.
- 7. Candidate For Discretion? [See attached list) Yes - potential escalation.
! During the last year, the licensee's performance in Operations has - declined from SALP 1 to SALP 2 (predecisional). There have been several
- operator violations of procedures that are, in part, related to the l i current violation
- j
- 1) VIO 335/94-22-02, " Improper Modification of Control Room Logs",
- November 25, 1994
! 2) NCV 335/95-07-01, " Failure to Follow Shutdown Cooling Operating Procedures", April 19, 1995 ! 3) VIO 335/95-15-01, " Failure to Follow Procedures and Block MSIS Actuation", October 16, 1995
- 4) VIO 335/95-15-02, " Failure to Follow Procedures during RCP Seal restaging", October 16,-1995
- 5) VIO 335/95-15-03, " Failure to Follow Procedure and Document abnormal valve position in the Valve Switch Deviation Log",
October 16, 1995 l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
4- ' 2-
- 6) VIO 335/95-15-04, " Failure to Follow Procedures during Alignment-j of Shutdown Cooling System", October 16, 1995
, 7). VIO 389/95-18-01, " Failure to Follow Procedures and Maintain , Current and Valid Log Entries in the Rack Key Log and Valve Switch j Deviation Log", November 27, 1995
- 8) VIO 389/95-21-02, " Failure to Follow the Equipment Clearance Order Procedure and Require Independent Verification of a TS Related Component", December 8, 1995 i
t All of the above-VIO/NCVs involved licensed operators with a licensee . ! corrective action commitment to strict adherence to procedures. j
- 8. Is A Predecisional Enforcement Conference Necessary?-
j Yes l
- Why: There is substantial interest in this event and in the NRC message j to the licensee and to the industry. The message for this enforcement ,
action should be that operators must treat-Dilution /Boration as i seriously as control rod manipulations. Also, that unusual operations .
- events must be transmitted promptly to management.
! If yes, should OE or OGC attend? Yes Should conference be closed? No 4
- 9. Non-R'outine Issues / Additional Information:
- 10. This Action is consistent With the Following Action (or Enforcement Guidance) Previously Issued: I.C.3 Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Message: The message for this enforcement action should be that operators must treat Dilution /Boration as seriously as control rod manipulations. Also, that unusual operations events must be transmitted promptly to management.
- 12. Recommended Enforcement Action: SLIII with CP
- 13. This Case Meets the Criteria for a Delegated Case. No Should This Action Be Sent to OE For Full Review? No,-informal review.
14. ,' 15. Regional Counsel Review To be determined at a later date. No Legal Objection Dated: ! PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE ., WITHOUT THE APPROVAL OF THE DIRECTOR, OE - i
4 7 5
- 16. Exempt from Timeliness: No Basis for Exemption:
- Enforcement Coordinator:
DATE:- .i l l I 1 PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
1 6 , ENFORCEMENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION O Problems categorized at Severity Level I or II. O Case involves overexposure or release of radiological material in excess of NRC requirements. O Case involves particularly poor licensee performance. O Case (may) involve wi11 fulness. Information should be included to address whether or not the region has had discussions with OI regarding the case, whether or not the matter has been formally referred to 01, and whether or not OI intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included.
@ Current violation is directly repetitive of an earlier violation (in part).
O Excessive duration of a problem resulted in a substantial increase in risk. O Licensee nade a conscious decision to be in noncompliance in order to obtain an economic benefit. O Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) O Licensee's sustained performance has been particularly good. O Discretion should be exercised by escalating or mitigating to ensure that the proposed civil penalty reflects the NRC's concern regarding the violation at issue and that it conveys the appropriate message to the licensee. Explain. i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE I
g 7 Enclosure 3 REFERENCE DOCUMENT CHECKLIST [] NRC Inspection Report or other documentation of the case: NRC' Inspection Report Nos.: [] Licensee reports: , [] Applicable Tech Specs along with bases: [x] Applicable license conditions [x] Applicable licensee procedures or extracts [] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results [x] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or Confirmation of Action Letters l [] Current SALP report sumary and applicable report sections 1 [] Other miscellaneous documents (List): i l l 1 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
.j l
8 . PROPOSED VIOLATION I
, A. ~ Technical Specification (TS) 6.8.1.a required that written procedures be established, implemented, and maintained covering the activities- l recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February 1978.. Appendix A includes operating procedures for the chemical and volume control system and administrative procedures for relief turnover, procedural adherence, and authorities and responsibilities for safe ,
operation. , Operating Procedure No. 1-0250020, Boron Concentration Control Normal Control, Rev. 35, step 8.5.14 required that operators monitor the water flow totalizar and close valve V2525 after the desired volume was added : during a boron concentration dilution using the direct path to the charging pump suction. Administrative Procedure No. 0010120, Conduct of Operations, Rev 79,' Appendix D, Crew Relief / Shift Turnover, required that, for short term watchstander relief, a turnover be conducted including: general watchstation status, off-normal conditions, and tests in progress. i
; Administrative Procedure No. 0010120,-Appendix M, Procedural Compliance and Implementation, required that controlled procedures be implemented and complied with in accordance with the instructions provided in QI 5-i PR/PSL-1. Procedure QI 5-PR/PSL-1, Preparation, Revision, ,
l Review / Approval of Procedures, Rev 67, Section 5.13.2, stated that all l procedures shall be strictly adhered to and identified that Operating i Procedure 1-0250020 was not considered " skill of the trade" and was not 1 to be performed from memory without referring to the procedure. AdministrativeProcedureNo.Obl0120,'AppendixE,Notificationof Operations Supervisor /FPL Management, required prompt verbal notification of the Operations Supervisor for unplanned reactivity changes. Contrary to the above:
- 1. On January 22, 1996, at approximately 2:30 a.m., Unit 1 operators failed to close valve V2525 after the desired volume was added during a boron concentration dilution using the direct path to the charging pump. Operators had desired to add between 25 and 40 gallons of primary makeup water, but failed to stop the dilution until approximately 400 gallons were added. During this time, the. i temporary relief operator at the controir was unaware that a boron concentration dilution was in progress, which resulted in an unmonitored reactivity addition. The SRO and other operators in the control room were also unaware that a reactivity addition was
-in progress.
- 2. On January 22, 1996, at approximately 2:30 a.m., the Unit 1 operator at the controls conducted a short term watchstander relief with an inadequate turnover in that it failed to include general watchstation status and conditions including that a boron PROPOSED ENFORCEMENT ACTION - NOT FOR PUSUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE G
0 . .
l
,3 9 l a
concentration dilution was in progress. As a result', the relief > operator at the controls was unaware that a boron concentration ! . dilution was in progress and failed to adequately monitor and ; control the dilution.
- 3. . On January 22,-1996, at approximately 2:30 a.m., operators'
[ performed Operating Procedure 1-0250020 from memory, without referring to the procedure, and without strictly adhering to the 1 . procedure. At the time, the procedure was written such that the , boron concentration dilution that was performed could not have 1 been performed by strictly adhering to the procedure.
'4. On January 22, 1996, between 2:30 a.m. and 7:20 a.m., operators failed to give prompt verbal notification to the Operations +
Supervisor for unplanned reactivity changes that had occurred. l B. -The Facility Operating License for St. Lucie Unit I authorizes the , licensee to operate the facility at a steady state reactor core power level'not in excess on 2700 megawatts thermal (MWt). TS 1.25 defines rated thermal power to be a total reactor core heat transfer rate to the ! i reactor coolant of 2700 MWt. TS 1.33 defines thermal power to be the i total reactor heat transfer rate to the reactor coolant. 1 Contrary to the above, on January 22, 1996, between approximately 2:20 i and 3:30 a.m., the reactor core thermal power level limit of 2700 MWt l (100%) was exceeded, due to operator inattentiveness. 100% reactor i power was exceeded for approximately;70 minutes. Also, 101% reactor n power was exceeded for approximately 4 minutes and a peak reactor power
- . of approximately 101.18% was reached.
C. 10 CFR 50.59 allows the licensee to make changes to the procedures as L described in the Safety Analysis Report (SAR), without prior Commission . approval, unless the change involves, in part, an unreviewed safety ( question. A proposed change shall be deemed to involve an unreviewed safety question if, in part, the probability of occurrence of an accident important to safety previously evaluated in the SAR may be increased. The licensee shall maintain records of changes in procedures
- j. made pursuant to this section, to the extent that they constitute changes in procedures as described in the SAR. These records must include a written safety evaluation which provides a basis for the
- determination that the change does not involve an unreviewed safety question.
! Contrary to the above, on January 23, 1996, the licensee made a change in Unit 1 procedures as described in the SAR and the records for that
~c hange did not include a written safety evaluation. Temporary Change 1-
! 96-017 to procedure 1-0250020,. Boron Concentration Control - Normal L Operation,-Rev. 35, added instructions for dilution in manual and
- ~ directly to the suction of the charging pumps. However, the SAR, paragraph 15.2.4.1, states that baron dilution is conducted under strict
, administrative procedures which limit the rate and magnitude of any required change in boron concentration. Further, the SAR states that boron dilution must be conducted in automatic (such that when the PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE
- i. WITHOUT THE APPROVAL OF THE DIRECTOR, OE
t 4 10 , 1
- specific amount has been injected, the domineralized. water control valve
- is shut automatically) and describes introduction into the volume-
, - control tank (VCT). The SAR concludes that, in part, because of the i procedures involved,.the probability of.a sustained or erroneous 4 dilution is very low. The licensee implemented Temporary Change 1 017 on January 23, 1996, without a written safety evaluation. I i 'l } General ' Description of the Event At approximately 0225 on January 22, 1996, the Unit I control board Reactor ' Controls Operator (RCO) began a manual dilution to the RCS by aligning primary makeup water (demineralized water)- directly to the suction of the -18 Charging - 1 Pump.. Moments after beginning the dilution, the board RCO responded to a
- secondary plant annunciator and then saw the desk RCO return from the kitchen.
!- He requested that the desk RC0 relieve him so that he could prepare his lunch. 3
- During the turnover, there was no discussion of the dilution in progress.
Following the turnover, the relief operator at the controls and the Nuclear
- Plant Supervisor-(NPS), who was at the desk RCO station, were not aware that a dilution was in progress. The original board RCO returned between 5-10
. minutes later and immediately recognized his error. -He informed the other RCO - of the overdilution, which was overheard by the NPS, and stopped the dilution. ; ,E The NPS directed the ANPS take charge and begin a manual boration. Unit 1 i entered 2-hour TS LCO Action Statement 3.2.5 for T, greater than 549'F. The
- - maximum T, obtained was 549.9'F and the maximum reactor power was 101.18%. T, was above the TS limit of 549'F for approximately 50 minutes and reactor power "
i
' was above 100% for approximately 70 minutes. The TS LCO Action Statement for
. T, was not exceeded and the guidance of the Jordan memorandum on maximum i reactor power was not exceeded. The operators did not verbally notify plant 3 management or the NRC of this event. Detailed Seouence'of Events (Note that the times for the sequence of events are approximate and only ! relevant events are mentioned) 1/21/96 11:00 p.m. Incoming mid shift assumed Unit I responsibility with the Unit at 100% power, 870 MWe, Tavg at 575 degrees F, Thot at 600 degrees F, Tcold at 548.9 degrees F, RCS Boron concentration at 376 ppm, Xe worth at -2722 pcm, all CEAs fully withdrawn and manual, and no . Technical Specification action statements in effect. Major evolution planned for the shift was to place the waste gas system in service. Further, there was an annunciator alarm E-9 associated with circulating water pump lube water supply strainer . delta P high that was intermittently coming in due to a failed pressure switch. 11:45 p.m. Board RCO reset to zero'the primary water (to VCT or charging pump) flow totalizer in preparation for inventory balance (RCS
- PROPOSED ENFORCEMENT ACTION NOT FOR PUBUC DISCLOSURE 4-WITHOUT THE APPROVAL OF THE DIRECTOR, OE ;
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,. ..o - ,_ m,,., . , _ _ _ _ . . , _ _ _ _ _ _ __
i 11
- j. leak rate calculation)'
i ll:00' p.m.- 2:00 a.m The board RCO recalled performing at least two dilutions of approv.imately 35 gallons each between 11:00 p.m. and 2:20 a.m. withc1t resetting the totalizer. l
] 1/22/96 xx:xx a.m NPS arrived in Unit I control room to gather data for morning '
4 report meeting and sat near desk behind control boards. STA was 4- a,lso present naar NPS
- xx:xx a.m. 'ANPS turned over control room senior reactor operator responsibility to NPS and proceeded to the kitchen to prepare breakfast- ,
$ xx:xx a.m. Desk RCO left control room to go to the kitchen 2:20 a.m. Normal continued fuci burnup resulted in indicated Tc of 548.7 , degrees F on RTGB-104 (digital meter). At this point the board , RCO decided to restore Tc to maximum allowable program value of 549.0 degrees F. xx:xx a.m. Desk RC0 arrived in the control room with his meal l 2:25 a.m. The board operator began a manual dilution by aligning primary i water to the suction of the charging pumps by opening FCV-2210X and A0V-2525. The flow rate was approximately 44 gpm. 2:26 a.m. Annunciator E-9 associated with circulating water lube water ' , supply strainer high delta P was received. The board RCO walked 4 to the panel and acknowledged the annunciator. , 1 2:27 a.m. After acknowledging the annunciator, the board operator decided to proceed to the kitchen to prepare his meal. The board operator
- conveyed this to the desk operator and requested that he take over the board operator responsibilities. However, he did not mention l the ongoing dilution. The desk operator got up and proceed to the i board in the vicinity of panel 103. The original board operator
- proceeded to the kitchen and started preparing his meal on a skillet that had been kept wann. At this time the NPS and the STA were in the control room at the desk area. The NWE had been in and out of the control room throughout the shift. The relief operator at the controls, NPS, STA, and NWE were not aware of the
, ongoing dilution.
.2:35 a.m. The original board operator returnd from the kitchen with his <
meal. Upon approaching the board, he realized that he had left . l the control room with an ongoing manual dilution. He exclaimed ) , that he had overdiluted arid immediately began securing the dilution. The desk operator questioned how much water.was added and the board operator noted from the totalizer that approximately PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE i l 4 s _ _ __ - - _ _ _ ___ _ _ .-.
, 12 .
400 gallons was added. 2:35 a.m. Soon after, annunciator M-16 associated with RCP controlled-bleedoff. pressure.high was received.. At this point the Tc was . noted by the desk operator to be 549.6 degrees F. Entry into two
, hour action statement associated with Technical Specification
- 3.2.5, DNB paramenters was recognized and later logged.
2:36 a.m. The desk operator directed the board operator to initiate boration to restore Tc to program. The NWE calculated the amount of borated water to be added to the RCS. The NPS asked the desk 4 operator to notify the unit ANPS to come to the control room. x:xx a.m. ANPS walked into the control room. 2:41 a.m. Tc reached the highest noted value of 549.9 degrees F. MWe reached 875 and indicated reactor power was approximately 101.2% i. x:xx a.m. Operator secored boration. 3:14 a.m. Tc noted below 549.0 degrees F. Technical Specification action statement was exited. -
~
x:xx a.m. STA initiated an In-House Event Report and notified HPES personnel by telephone. 5:45 a.m.- 6:00 a.m. Shift turnover occurred. It appears that the dilution event was not discussed with the oncoming shift. l 6:25 a.m. In-House Event Report was E-mailed to standard distribution, which included plant management, by the STA. 6:30 a.m. The Operations Manager toured the control room but was not informed of the over dilution event.
- 7
- 20 a.m. The Operations Manager read the control room logs (in his office by computer) and questioned the log entry associated with the overdilution event.
7:30 a.m. Licensee initiated a detailed investigation associated with the event. t 7:45 a.m. Senior Plant management was notified of the event during the morning meeting. 10:00 a.m. NRC resident inspector was given the event report that was initiated associated with the event. . i l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
O 4 i 13 ST. LUCIE ONSITE EVENT FOLLOWUP INSPECTION OVERDILUTION EVENT of 1/22/96 (Exit was at 10:00 a.m. on 1/30/96) Inspectors: R. Schin, S. Sandin, B. Desai Sn=ery of draft creliminary findlDE1:
- 1. Magnitude of power ar.d temperature excursion
- a. Reactor power
- Peak reactor rower was apprcximately 101.18%
- 100% power was exceeded for approximately 70 minutes
- 101% power was exceeded for approximately 4 minutes
- The event was within the accident analysis
- The guidelines of the Jordan memo were not exceeded
- b. Cold leg temperature
- Peak Tc was approximately 549.9 degrees F
- TS limit of 549 was exceeded for approximately 50 minutes
- TS 2-hr. action statement was properly entered and was not exceeded
) 2. Concern with operator attentiveness - Potential / Apparent VIO of j procedures (Enforcement panel form completed on this issue):
- a. . Operators failed to stop dilution when the proper amount had been j added.
- b. There was inadequate watch turnover for the operator at the controls during dilution.
4
- c. Operators failed to follow the Conduct of Operations procedure in performing the dilution procedure..
4 d. Operators failed to adequately report the event to licensee managernt.
- 3. Concern with u,ntrol room comand and control - Weakness
- a. The SR0 in the control room was not aware of the dilution in a
progress,
- b. The board operator did not inform the SRO of dilution - this was a general practice at the site and not required by procedures.
- c. The watchstander board was not maintained (on Saturday).
- d. The SR0 in the control room was allowed to be in the ANPS office for unlimited time, out of sight of control room activities and out of hearing range of almost all control room activities except annunciator alarms (not applicable during this event).
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
1 l-li . . t
-4.- Weaknesses in procedures .
- a. The Unit 2 dilution procedure had been. changed, but not the Unit 1 ,
procedure, to more accurately describe dilution the way the : 4 operators had performed it for years (in manual and direct to the charging pumps). -During the event, manual dilution could not be accomplished by using the Unit 1 procedure in compliance with the Conduct of Operations.
- b. Procedures and practices for dilution (before and during the .
event) did not support the FSAR accident analysis assumptions en ' how dilution was performed. The FSAR assumed dilution in automatic and to the VCT.
- c. Procedures for dilution (before and during the event) did not require the operator at the controls to remain by the dilution controls and to closely monitor the dilution during a manual dilution with'no automatic shutoff.
- 5. Weaknesses in corrective action <
' a. Potential VIO of 10 CFR 50.59: Revised procedure (after the event) did not support the FSAR Chapter 15 accident analysis assumptions on how dilution was performed. The FSAR assumed ,
dilution in automatic and to the VCT.
- b. ,The revised procedure for manual dilution (after the event) did not require the operator at the controls to remain by the dilution i controls and to closely monitor the dilution during a manual ;
dilution with no automatic shutoff. 1 I
- c. The licensee initial investigation of the event was not thorough l in that it concluded that maximum reactor power was 100.2%. l Subsequent review by the NRC and licensee found'that maximum ,
reactor power was approximately 101.18%. l
- 6. Weakness in Operational Experience Feedback
- a. In response to SOER 94-02, dated September 1994, which described a similar Turkey Point overdilution event and several inadvertent 3 dilution events'at other utilities, the licensee reviewed the St. l Lucie operating procedures. related to dilution and concluded that -
no changes were needed. This was a missed opportunity to ! strengthen operating procedures to prevent the 1/22/96 overdilution event.
- 7. Other comments'
- a. There was no clearly noticeable indication of dilution in progress. The dilution clicker was quiet (might not be heard from the desk area) and sounded identical to the nearby clickers that routinely made noise.
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR, OE '
2 . a 4 y
- b. Operators routinely did not log reactivity additions; however, the
; licensee's Conduct of Operations procedure stated that operators
- should log reactivity changes.
L ICENSEE DISSENTING COMENTS
- 1. The licensee had dissenting comments on item 5.a. above, the potential violation of 10 CFR 50.59. The inspectors told the licensee at the exit :
that those dissenting comments would be included in the inspection report, for further review by NRC management. The dissenting comments,. 3 from the engineering utnager.(Dan Denver) and the licensing manager (Ed l Weinkam), included: f j a. The previous. procedure allowed diluting in manual and directly to 1 the suction of the charging pumps, and that had been the practice for many years. Therefore, the temporary change on 1/23/96 (after
- the event) did not change the method of dilution, but only clarified a previously existing procedure and made it conform to
" verbatim compliance" rules. The inspectors did not disagree. In ,
fact, further review, as requested by the inspectors, found that the first time the dilution procedure was changed to allow opening . of valve 2525 (directly to the suction of the charging pumps) was in a change to rev. 2 of the procedure, in 1976, before the : operating license was issued. !
- b. The design af the plant (piping, valves) always was such that dilution in manual and directly to the suction of the charging pumps was possible. The inspectors did not disagree.
- c. The accident analysis assumed a worst case dilution event with demineralized water going directly to the suction of the charging e pumps and three charging pumps running. That would be three . times the flowrate of this event and therefore that analysis bounds this i event. The inspectors did not disagree. ,
, d. The FSAR Chaptt 9 description of the Chemical and "Alume fontrol System did not prohibit dilution in manual and directiy to the suction of the charging pumps. The inspectors did not disagree.
! e. The automatic mode of dilution is less safe than the manual mode, ; in that there is more opportunity for a malfunction that could ' l result in a maximum flowrate approaching the design limit. The inspectors did not comment on that position. 1 f. The procedure change that first allowed dilution directly to the suction of the charging pumps was made before the operating s license was issued, therefore 10 CFR 50.59 did not apply to that change. The inspectors did not comment on that position.
- g. Since the operating procedure that was in effect at the time the operating license was issued allowed dilution in manual and directly to the suction of the charging pumps, that method was PROPOSED F.NFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE 6,...- , ,-
.--r-r- - ,. - . .-,e.. .,. - - - _ ____ ____-____ _ _ -
. . o included in the original l licensing basis of the plant. The ,
inspectors did not agree with that position.
- h. After receiving these licensee comments, the inspectors' concern remained unchanged: The Temporary Change of 1/23/96 (after the event) describ6d procedure steps for dilution in manual and i directly to the suction of the charging pumps. . That procedure was i different from the one described in the FSAR. The licensee's procedure differed from the FSAR in that it allowed a faster rate of reactivity addition and without an automatic shutoff. The licensee had not performed a safety analysis of this difference and had not revised the procedure and/or FSAR to make them agree. ;
- 2. The licensee also had a dissenting comment on item 5.c. above, the r weakness in the licensee's initial investigation. The dissenting comment, from the Plant Manager (Jim Scarola), was
$ a. The initial investigation, for the In-House Event Summary, was done by the STA. Timeliness was more important than quality at , 4 that time. Subsequent more thorough review would be performed by ! the licensee. The inspectors acknowledged the licensee's comment. : i i i d
)
) i I i i i k i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
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l i Proposed Operator NOTICE OF VIOLATION i 4 Docket No. 55-License No.0P-EA(s) TBD 3 During an NRC inspection conducted on January 26-30, 1996, violations of NRC l
! requirements were identified. In accordance with the " General Statement of I Policy and Procedure for NRC Enforcement Actions," NUREG-1600, the violations are listed below:
i Technical Specification 6.8.1.a required that written procedures be established, implemented, and maintained covering the activities i recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February i' ' 1978. Appendix A includes operating procedures for the chemical and
- volume control system and administrative procedures for relief turnover, procedural adherence, and authorities and responsibilities.for safe 4
operation. Operating Procedure No. 1-0250020, Boron Concentration Control - Normal Control, Rev. 35, step 8.5.14 required that operators monitor the water flow totalizer and close valve V2525 after the desired volume was added j during a boron concentration dilution using the direct path to the l charging pump suction. ) Administrative Procedure No. 0010120, Conduct of Operations, Rev 79, l ! l Appendix D, Crew Relief / Shift Turnover, required that, for short ters watchstander relief, a turnover be conducted including: general l watchstation status, off-normal conditions, and tests in progress. j I t Administrative Procedure No. 0010120, Appendix M, Procedural Compliance ) and Implementation, required that controlled procedures be implemented l l and complied with in accordance with the instructions provided in QI 5-l ! PR/PSL-1, Preparation, Revision, Review / Approval of Procedures, Rev 67. ! l Procedure QI 5-PR/PSL-1 Section 5.13.2, stated that all procedures shall be strictly adhered to and specifically identified that Operating Procedure 1-0250020 was not considered " skill of the trade" and was not to be performed from memory without referring to the procedure. Contrary to the above:
- 1. On January 22, 1996, at approximately 2:30 a.m., the Unit 1 4 operator failed to close valve V2525 after the desired volume was l j
l added during a boron concentration dilution using the direct path ' to the charging pump. The operator had desired to add between 25 l and 40 gallons of primary makeup water, but failed to stop the dilution until approximately 400 gallons were added. During this , 1 time, the temporary relief operator at the controls was unaware
- that a boron concentration dilution was in progress, which.
resulted in an unmonitored reactivity addition. The SRO and other
- . operators in the control room were also unaware that a reactivity addition was in progress.
4
f i i
- 2. On January 22, 1996, at-apprc.?imately 2:30 a.m., the Unit 1 '
operator at the controls condu-ted a short term watchstander relief with an inadequate turno.*er in that he failed to include i
- - general watchstation status and cnnditions including that a boron ,
l concentration dilution was in progress. As a result, the relief '
- operator at the controls was unaware that a boron concentration
' dilution was in progress and failed to adequately monitor and l control the dilution. ,
- 3. On January 22, 1996, at approximately 2:30 a.m., the Unit I ;
! operator. performed Operating Procedure 1-0250020 from memory, i ! without referring to the procedure, and without strictly adhering , l to the procedure. At the time, the procedure was written such : that the boron dilution that was performed could not have been j performed by strictly adhering to the procedure. ; l .These violations represent a Severity Level III problem (Supp ement- l ). -l I : Pursuant to the provisions of 10 CFR 2.201, ************* is hereby required l to submit a citten statement or explanation to the U.S. Nuclear Regulatory ; Commission, ATTN: Document Control Desk, Washington, D.C. 20555 with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident 4 Inspector at the facility that is the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should be clearly marked as a " Reply to a Notice of Violation" and should include for each violation: (1) the reason for the violation, or, if
- contested, the basis for disputing the violation, (2) the corrective steps
- that have been taken and the results achieved, (3) the corrective steps that.
- will be taken to avoid further violations, and (4) the date when full compliance will be achieved. Your response may reference or include previous docketed correspondence, if the correspondence adequately addresses the required response. If an adequate reply is not received within the time
- specified in this Notice, an order or a Demand for Information may be issued as to why the license should not be modified, suspended . or revoked, or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extending the response time.
I Under the authority of Section 182 of the Act, 42 U.S.C. 2232, this response shall be submitted under oath or affirmation. i Because your response will be placed in the NRC Public Document Room (PDR), to the extent possible, it should not include any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without
- - redaction. However, if you find it necessary to include such information, you
- should clearly indicate the specific information that you desire not to be placed in the PDR, and provide the legal basis to support your request for withholding the information from the public.
~
- Dated at Atlanta, Georgia this day of Februay.1996 j
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r . ENFORCEMENT ACTION j WORKSHEET
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INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL ST! LUCIE UNAUTHORIZED ACCESS i PREPARED BY: Lori Stratton DATE: 10/30/96 j NOTE: The Section Chief of the responsible Division is responsible for i pre 3aration of this questionnaire and its distribution to attendees prior to ! an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and tele) hone bridge number to attendees via e-mail [ENF.GRP. CFE. OEMAIL. JXL. JRG. SiL. LFD: appropriate RII DRP. DRS: appropriate NRR. NMSS]. A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is required. Copies of applicable Technical Specifications or license conditions cited in the ; Notice or other reference material needed to evaluate the proposed enforcement ; action are required to be enclosed. This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. Signature I
- 1. Facility: St. Lucie Unit (s): 1 and 2 Docket Nos: 50-335. 50-389 License Nos: DPR-67. NPF-16 Inspection Report No: 96-19 i Inspection Dates: 10/21 - 10/25/98 )
Lead Inspector: L. Stratton l
- 1. Brief Summary of Inspection Findings:
A. 10 CFR 73.55(7) requires that licensee's shall establish an access authorization system to limit unescorted access to vital areas 4 during non-emergency conditions to individuals who require access in order to perform their duties. The licensee's Physical Security Plan (PSP). Revision 48.. dated 2/23/96 states. "Only those individuals with identified need for access and having appropriate authorization, shall be granted unescorted Vital Area access." Contrary to the above, from July 28, 1996 to September 19. 1996 an individual whose employment terminated on July 28, 1996, had unescorted access to protected and vital areas without appropriate authorization. In addition, on August 7: August 9: and August 15. 1996, that individual entered the protected area and had access to vital areas. kN PREDECISIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR. OE
f , ENFORCEMENT ACTION ' WORKSHEET Also, three other individuals had unescorted access to the l
' protected and vital areas after they were terminated from the period of July 27 to September 19. 1996, without appropriate authorization. However, those individuals did not access the protected or vi.tal. areas.
'B. 10 CFR 73. Appendix G. states that an actual entry of an i unauthorized person into a protected area or vital area be '
reported within one hour of discovery. 10 CFR 73. Appendix G. states that any failure, degradation, or
. discovered vulnerability in a safeguards system that could have allowed unauthorized or undetected access to a protected area or a vital area had compensatory measures not been established, be recorded within-24 hours of discovery in the safeguards event log.
Contrary to the above, on October 9. 1996, the licensee discovered - that an individual had been terminated on July 28. 1996, and had ' entered the protected area on five different occasions, yet failed to make a report within the one hour timeframe. In addition, on September 19. 1996, the licensee discovered three individuals who had previously been terminated on July 27. July 28. and August 24, 1996 that had access to the protected area and failed to report that discovery in the safeguards event log.
- 2. Analysis of Root Cause:
Violation A: Responsible organizations failure to adhere to Administrative Procedure (AP) 0010509 " Personnel and Material Control." Revision 18. dated 9/30/96 and notify security when individuals were tenninated. Also. those organizations' inadequate review of the 31 day vital area access lists. Violation B: Security's failure to implement Security Procedure (SP) 0006125. " Report , of Safeguards Events." Revision 10. dated 10/9/96.
- 3. Basis for Severity Level (Safety Sionificance): [ Include example from the supplements, aggregation, repetitiveness, willfulness, etc.]
Violation A: Supplement III. SL III The NRC Enforcement Policy states as example "A failure or inability to control access through established systems or procedures, such that an unauthorized individual (i.e.. not authorized unescorted access to the protected area) could easily gain undetected access into a vital area from outside the protected area." ; PREDECISIONAL ENFORCEENT INFORMATION . NOT FOR PUBLIC i RELEASE W/0 APPROVAL OF DIRECTOR OE
t._ ENFORCEMENT ACTION 3-WORKSHEET Violation B: Supplement'III. SL'III The NRC Enforcement Policy states in Section 7.10. "The severity level assigned to the licensee's failure to submit a required, acceptable, and timely report on a violation that occurred at the licensee's facility is normally the same as would be assigned to the violation that should have been reported. However, the severity level for submitting a late report may be reduced, depending on the individual circumstances. NOTE: This is a first repeat of this violation with respect to failure to make a one hour report.
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
[by EA# Supplement, and Identification date.]
-- 95-180: PORVs Inoperable Due To Personnel Error. SL III 96-040: Dilution Event: SL III 96-249: Multiple Examples of Inadequate 50.59 Reviews: SL III
- 5. Identification Credit? [ Enter Yes or No): No Consider following and discuss if applicable below:
o Licensee-identified a Revealed through event a NRC-identified a Mixed identification a Missed opportunities Violation A:
- Security immediately removed the individuals' access when discovered.
However. The licensee missed an opportunity to evaluate their access program on 8/19/96, when Condition Report (CR) 96-2041 was issued. This l CR identified that an individual was presented a FPL severance package and his access was still valid 12 days later. In addition, although Security did r.emove the individuals' access authorization, they missed an op]ortunity to validate that those individuals did not use their unautlorized access from the date of their respective terminations. Violation B: , 1 Several missed op>ortunities with respect to reportability occurred at St. Lucie. (a) T1e security access coordinator on September 39 failed to notify any other personnel when he discovered three individuals had unauthorized access. Therefore, the event was not logged in the safeguards event log. (b) When the security access coordinator learned on October 9 that one of the individuals he had earlier identified as having unauthorized access actually entered the protected area, he did notify his supervisor. However, the event was neither one hour reported nor logged in the safeguard event log. (3) When the Security Manager ' learned of the event of October 11, a determination was made to put the event in the safeguards event log rather than make a one hour report. The event was eventually reported on October 16. l PREDECIsIONAL ENFORCEENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL oF DIRECTOR. OE
r . ENFORCEMENT ACTION 4-WORKSHEET A possibility exists that if the individual did not apply for a position at Turkey Point and had his processing for that position conducted by the St. Lucie staff for convenience purposes, the problem would not have been identified. (See attached chronology for more specific details). Enter date Licensee was aware of issues requiring corrective action: Violations A and B: September 19, 1996
- 6. Corrective Action Credit? [ Enter Yer, or No]: No.
Brief summary of corrective actio,s: Violation A:
- Security immediately removed the individuals' unescorted access to the protected and vital areas
- FP&L inter-office correspontace dated October 25 to all responsible organizations that by COB 10/30/96, an access review and certification that all individuals listed on the attached access lists are valid.
- A comparison of a listing of 594 terminated individuals to the security computer to verify that unescorted access was correct, which was started October 17 and completed October 31. Out of those 594, three more individuals were identified. Two individuals were identified for Turkey Point and one individual was identifled with unauthorized access to both facilities.
- However, an inadequate assessment of CR 96-2041 which resulted in no specific corrective action could have identified to the licensee a problem existed as early as 8/19/96. Also, again on 9/19/96, when the access coordinator discovered the three individuals who had unauthorized access. Finally on October 9 when the licensee discovered an individual had entered the
)rotected area after termination, the licensee once again should lave identified a problem existed with respect to terminations and unescorted access, Not until the period of October 16, when the event was called to the NRC to October 25, when CR 96-2496 was generated, did the licensee recognize a significant problem existed.
Violation B:
- The licensee did eventually determine a one hour report was warranted.
No other corrective action had been initiated. The corrective action generated by the violation cited in IR 96-16 was partially complete when the events occurred and fully completed prior to the PREDECis10NAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL oF DIRECTOR, OE
t o ENFORCEMENT ACTION WORKSHEET - finfsh of the inspection. However, the corrective action for IR 96-16 was to change the procedure to include tampering events, whereas the cause of these violations was adherence to the procedure itself. 7, Candidate For Discretion? [See attached list] [ Enter Yes or No]: ; Indeterminate. The licensee's failure to report the event within one hour is a repeat violation.
-8. Is A Predecisional Enforcement Conference Necessary?
[ Enter Yes or No): Yes. Why: To facilitate a better understanding of root cause and missed opportunities. If yes, should OE or OGC attend? [ Enter Yes or No]: Yes Should conference be closed? [ Enter Yes or No]: No j
- 9. Non Routine Issues / Additional Information:
Seo attached chronology.
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: [EICS to provide] [If inconsistent, include:]
Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Message: Encouragement of prompt identification and prompt comprehensive corrective action.
- 12. -Recommended Enforcement Action:
Severity Level III and Severity Level IV violation.
- 13. This Case Meets the Criteria for a Delegated Case. [ETCS - Enter Yes or No]
No ,
- 14. Should This Action Be Sent to OE For Full Review? [EICS - Enter Yes or No]
No If yes why: PREDECIsIONAL ENFORCEMENT INFORMATION . NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR. OE
- r. s ENFORCEMENT ACTION. '
WORKSHEET
- 15. Regional Counsel Review [EICS] At the panel.
No L.egal Objection Dated:
- 16. Exempt from Timeliness: [EICS) No.
Basis for Exemption: Enforcement Coordinator: DATE: O I PREDECISIONAL ENFORCEENT INFORMATION NOT FOR PLELIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
; c ENFORCEMENT' ACTION WORKSHEET i
ISSUES TO CONSIDER FOR DISCRETION o Problems categorized at Severity Level I or II. o Case involves overexposure or release of radiological material in excess of NRC requirements. o Case involves particularly poor licensee performance. o- Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with OI regarding the case, whether or not the matter has been formally referred to 01, and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard willfulness, and/or management involvement should also be included. O Current . violation is directly repetitive of an earlier violation. o Excessive duration of a problem resulted in a substantial increase in risk. 2 o Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. o Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) o Licensee's sustained performance has been particularly good. o Discretion should be exercised by escalating or mitigating to ensure that the proposed civil )enalty reflects the NRC's concern regarding the violation at issue and tlat it conveys the appropriate message to the licensee. Explain. 1-4 PREDECISIONAL ENFORCENENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
- r. ,
CHRONOLOGY
- UNAUTHORIZED INDIVIDUAL-ENTERING THE PA AFTER TERMINATION 7/28/96 Employee terminated.
8/19/96 CR'96-2041 identifies an individual having access to the site 12 -
- days after termination.
9/19/96 PSL Access Coordinator identifies employee terminated and removes , the individual's access (along with 2 others), but fails to notify , Security. t 10/7/96 TPN contacts PSL Access Coordinator to process this individual for TPN access. 10/9/96 During the processing of this individual, the PSL Access 4 Coordinator notices that the employee's last badge use date is after his termination date. Further review reveals the individual had entered the PA on 5 occasions (3 different days). Upon interview of the individual, the licensee learns he returned for an interview on one occasion. However, on the other occasions, came back to talk to other people in general. The Access
- Coordinator notifies the security supervisor, who determines the ;
event as non-reportable. , 10/11/96 The Security Manager learns of the situation and logs the event in the licensee's SEL. CR is generated. 10/16/96 The licensee determines the event to be one hour reportable. Call made to Region II (Stratton) and OPS Center. PROBLEMS:
- 1. Procedure does not provide a form / checklist for termination.
- 2. Procedure denotes responsibility to the individual. their supervisor, and human resources to notify security upon termination. All three individuals failed to do so.
- 3. No training on the procedure. Limited distribution of the procedure, however, the procedure is available to anyone.
- 3. Access Coordinator's failure to notify security and recognize the seriousness of the situation and failure to log the event in the licensee's SEL, s
- 4. Security's failure to one hour report the event after learning the individual had entered the protected area. IR 96-16 (tampering event
- report) also identified a violation for failure to report.
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- 5. The licensee's missed opportunity to investigate / correct the problem ,
when CR-2041 was identified. This was a precursor to the event. j l
- 6. If the individual had not processed in at PSL. the problem may not have been identified, and the licensee would still not know an unauthorized individual had entered the PA.
- 7. Corporate 0A had responsibility to ensure compliance with this procedure. No evidence that was ever initiated.
- 8. This problem is FPL wide. PTN also has identified individuals who had .
access after they were terminated. No other individuals who had access i after termination entered either site. Responsible organizations who failed to notify Security included Engineering. MIS. Human Resources. l
- I&C. and 0A.
- 9. Numerous severance packages are being offered in conjunction with many !
terminations at FPL.
- 10. Security's inadequate investigation of the event in that, the two people identified by the individual as being visited on the days when the ,
individual accessed the site were interviewed. That's all that was done l
- as far as Security's investigation. Upon independent inspection, this 4
ins)ector learned that the two individuals spent approximately 2 hours wit 1 the individual.1.5 hours on 8/15 and 15 minutes on 8/7. According to access records, the employee was in the protected area as follows: 8/7/96 12:02 - 12:45 (43 minutes) 8/7/96 12:59 - 14:28 (30 minutes) 8/7/96 14:37 - 17:15 (2 hours 38 minutes) ' 8/9/96 10:07 - 13:37 (3 hours 30 minutes) 8/15/96 12:47 - 17:37 (4 hours 50 minutes) i Approximately 10 hours inside the protected area are unaccounted for. l
- 11. Individual had PA and VA access. Did not enter any VAs during the times l noted above. !
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2 l ENFORCEMENT ACTION WORKSHEET EICS HEETING NOTES AND DOCUMENTATION OF U OERSTANDING II. Civil Penalty Assessment l A. First non-willful SL III violation in 2 vears/2 insoections? YES or NO Previous escalated cases: 1 . B. Identification Credit? YES - NO - N/A Mtc identified? Licensee identified? Revealed through an event?* Prior opportunities? t i C. Corrective action credit? YES - NO - N/A Immediate corrective actions: 1 Long term corrective actions to prevent recurrence: D. Discretion ano11ed? Yes or No: Reason why. I 4 E. Civil Penalty: F. Ree - .dation for credecisional enforc-- at conference: l w ,w-w w
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- ENRRCEENT ACTI(W MRKSEET EICS EETING NOTES M 00CtNENTATION OF UWERSTEING NOTE
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- ENFORCEMENT ACTION WORKSHEET EICS MEETING NOTES AND DOCUMENTATION OF UNDERSTANDING 4
II. Civil Penalty Assessment l A. First non willful SL III violation in 2 vears/2 insoections? YES or NO Previous escalated cases: B. Identification Credit? YES - NO - N/A
- MtC identified?
Licensee identified?
- Revealed through an event?*
Prior opportunities? l C. Corrective action credit? YES - NO - N/A i Immediate corrective actions: Long ters corrective actions to prewat recurrence: D. Discretion anolied? Yes or No: Reason why. E. Civil Penalty: ,
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- ENFORCEENT ACTION WORKSEET ,
EICS EETIE NOTES M DOCLMNTATION OF UpWERSTEIE l l
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l NOTE: Complete the following information for each violation I l ISSE: III. nnemantation of Enforcement Panel / Caucus Consensus
; A. Preliminary Severity Level (Prior to Application of any Discretion.
From Part I) I-B. Increase Severity Level based on Aggregation? : ]' C. Increase Severity Level for Repeat Violations? l (Address requirements of RDI 0903) 4 D. Increase Severity Level for W111 fulness? E. SEVERITY LEVEL SUPPLEENT/SECTION F. Recommended Civil Penalty
)
G. Predecisional Enforcement Conference Necessary? H. Revision to Draft NOV Required? I. Formal Review by OE Required? , J. Special Action Items / Nessage to Licensee / Comments
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SUBJECT:
M /Fw/ h d./*498 I" &M>rsaoll ~7. KneA) a PAKL a PEC yCAUCUS A Gibsou b BartS a OTER a OI BRIEF E #efM l M. Msller' \ INSPECTION EM) DATE: ; PREPARED BY: DATE: TIE: I. EICS STAFF NOTES: . Sbja11+rLC i d,4. ? M %e- Ink ofwaAvik. L Vlow /wif wg.s 6 roxA- U
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- VIA TilEPHOE
l 2 ENFORCEMENIACTIONWORKSHEET , EICS MEETING NOTES AND DOCUMENTATION OF UNDERSTANDING II. Civil Penalty M s.camorrt A. Fichi. i=, willful SL III violation in 2 vaars/2 insoections? YESorh Previous' escalated cases: I N j B. Identification credit? .ND - N/A ISIC identified? Licensee identified? Revealed through an event?* - _.
\.
l l Prior upportunities? ! i C. Corrective action credit? YES h - N/A , Iemediate wriidive actions: 4//9 m d W dA1A'l n Long tern currective actions to preisi recurrence: D. Discretion maalied? Yes or Reason why. Civil Penalty: 00 E. 3 F. "r-
- .detion for si kcisional wiTur-- -.t conference:
Y t 'e W 'R ' W
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ENFORCEENT ACTION WORKSHEET I EICS EETIE WIES AW DOCIENTATION OF UWERSTAEIN l WTE: Complete the following information for each violation ISSUE: III. Documentation of Enforcement Panel / Caucus Consensus A. Preliminary Severity Level (Prior to Application of any Discretion. From Part I) 7E' ed B. IncreaseSeverityLeve{basedonAggregation? edit C. Increase Severity Level for Repeat Violations? (A&hss requirements of ROI 0903) NM D. Increase Severity Level for Willfulness? E. SEVERITY LEVEL fC SUPPLEENT/SECTION 7E~ l F. Recommended Civil Penalty dfb,NO l G. Predecisional Enforcement Conference Necessary? H. Revision to Draft NOV Required? N.f- ' N I. Formal Review by OE Required? A/o - d #xtra4[ ded b J. Special Action Items / Hessage to Licensee / Comments 1 l l I
< . . _ . . . - . _ .. _,. . _ _ . _ _ . . _ . _ . . _ . _ , _ _ - ~ . . . _ . . . ._ _ _ _ _ . . _ . _ _ _ _ _ _ i i i l i i i i l 1 l i l 4 i l J l 1 I r i 1 i j l 1
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EICS ENFORCEMENT WORKSHEET EICS HEETING NOTES AND DOCUNENTATION OF UNDERSTANDING EA MAEER: b b~ $ ATTEIEEES
//MG FACILITY: DT. L uc 4E T.u ci A Q
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- SLEb/ Lit.KsoQ IllSPECTION EM)j,DATE
- (* VIA TELEPHOE)
PREPARED BY: UhL DATE: /2.I09/o TIE: I3*u I. EICSSTAFFNdTES: dle. Ja CA- nol n w & n A N %, ,in1 AFG,/ Bad A DK. O 2 10 %, )
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2 ENFORCEENT ACTION WORKSHEET EICS EETING NOTES M DOCUENTATION OF UWERSTMIE II. Civil Penalty Assessment A. First non willful SL III violation in 2 years /2 insoections? YES or Previous escalated cases: B. Identification Credit? YES NO - N/A RC identified? . Licensee identified? Revealed through an event?* Prior opportunities? C. Corrective action credit? YES NO N/A Immediate corrective actions: Long term corrective actions to prevent recurrence: 1 D. Discretion anolied? Yes or Reason why. I 1 I E. Civil Penalty: 1 F, Recommendation for Orc-decisional enforc._ .it conference: 4 ) %
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3 ENFECDENT ACTIGd M EICS EETING IUTES Alm DOCLBENTATION OF LM)ERSTAICING IETE: Complete the following information for each violation l 1 ISSLE: III. nanmaritation of Enforemen: Panel / Caucus Consensus i i A. Preliminary Severity Level (Prior to Application of air Discretion. , Fnia Part I) l B. Increase Severity Level based on Aggregation? ) 1 . C. Increase Severity Level for Repeat Violations? l (Address reprirements of RDI 0903) D. Increase Severity Level for Willfulness? E. SEVERITY LEVEL SlPPLEENT/SECTION F. Recommended Civil Penalty bk l l G. Predecisional Enforcement Conference Necessary? H. Revision to Draft NOV Required? 1
- I. Formal Review by CE Required? l J. Special Action Items / Message to Licensee / Coseents
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b EA NUMBER REQUEST FORM TO: OEMAIL OR FAX TO DE FROM: ANNE T. BOLAND REGIONAL CONTACT DATE OF REQUEST AUGUST 25,1995 REGION
- 11 l
UCENILEE FLORIDA POWER AND LIGHT COMPANY FACluTY/ LOCATION ST. LUCIE / JENSEN BEACH, FLORIDA UNITS 1 UCENSE/ DOCKET NO(S). DPR 67,50-335 LAST DAY OF INSPECTION AUGUST 28,1995 01 REPORT NO. NONE DATE OF 01 REPORT N/A
SUMMARY
OF FACTS OF CASE (ANNUAL REPORT FORMAT FOR EATS ENTRY)(MAXIMUM OF 300 CHARACTERS) UNIT 1 PORVs WERE INOPERABLE DUE TO PERSONNEL ERROR DURING MAINTENANCE AND INADEQUATE POST MAINTENANCE AND SURVEILLANCE TESTING FAILED TO DETECT INOPERABLE CONDITION. BRIEF
SUMMARY
OF INSPECTION FINDINGS flF NOT SUFFICIENTLY DESCRIBED ABOVE) THE PORVs WERE INOPERABLE DURING THE PERIOD 11/22-27/94 AND 2/27 3/6/95 WHEN THEY WERE REQUIRED DURING LTOP CONDITION THE INOPERABILITY WAS CAUSED WHEN THE GUIDE SLEEVE WAS REPLACED BACKWARDS DURING RE-ASSEMBLY FOLLOWING MAINTENANCE. POST-MAINTENANCE TESTING WAS INADEQUATE TO DETERMINE OPERABluTY AND DID NOT INCLUDE SENCH TF. STING WITH AIR TO ENSURE PROPER OPERATION, SUBSEQUENT SURVEILLANCE TESTING REUED PRIMARILY ON ACOUSTICAL MONITORING AND DID NOT INCLUDE ADEQUATE ACCEPTANCE CRITERIA WITH MULTIPLE INDICATORS TO VAUDATE OPERABluTY. PREDECISIONAL ENFORCEMENT CONFERENCE TO BE CONDUCTED . NOT YET SCHEDULED. REASON FOR' POTENTIAL ESCALATED ACTION " SUPPLEMENT l.C.2.A. A SYSTEM DESIGNED TO PREVENT OR MITIGATE A SERIOUS SAFETY EVENT NOT BEING ABLE TO PERFORM ITS INTENDED FUNCTION UNDER CERTAIN CONDITIONS. DELEGATED CASE YES X NO PHYSICIAN NUC PHARM RADIOG IRRAD MED INST WELL LOGGERS ACADEMIC GAUGE MOISTURE DENSITY OTHER TYPE: CITE SIMILAR CASE: EA NO, SHOULD OE ATTEND ENF CONF X YES X NO NONDELEGATED CASE X YES , NO X NONDELEGABLE TYPE 01 REPORT / WILLFUL COMPLEX / NOVEL DISCRETION COMM APPROVAL 01 INTEREST SL 1 OR 2 OTHER REASON: IS THERE A BASIS TO CLOSE ENFORCEMENT CONFERENCE? Y/N IF YES EXPLAIN: NO EA # ASSIGNED BY OE DATE: ES ASSIGNED l
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4 s BSCAL&TED ENPORCEMENT. PANEL .-
? QUESTIONNAIRE lOUIRED TO BE AVAILABLE PRIOR TO ENFORCEMENT PANEL
- leineorae/B1mira DATE PREPARED: Anril 7. 1993'- .
- tion. Chief ~ is responsible , for preparation of 1 this - ,
Tcad its; distribution. to attendees-. prior .to an . . ! in21. : (This. information will be - used by EICS to. ! cnforcement letter- and --Notice,. as well- as- the
- emo to the M Of fice of ~ Enforcement explaining and i R:gion's proposed' escalated: enforcement action.-)'
St:Lucie , Unit L2'
.c: 389 .foJ : NPF-16 .
in Dates:- March 10-17. 1993 i '.detor:2Ws 'P. Kleinsorae I l !! 1 aft Notice.of Violation, including the recommended ' irity level = for each violation, should be enclosed.
.. vic).ction (s) in- the Notice should be carefully sidered by.both the inspector and Section Chief, and ald be canrplete regarding the specific requirement to .
- itad cnd the appropriate level of specificity as to
,and when the requirement was violated. .i
- c3 of . applicable Technical Specifications or license alltions cited- in the Notice should be enclosed.- _ . . . , ._
l l tha roference'to the Enforcement Policy Supplement (s) l , fits the violation (s) (e.g., Supplement I.C.2) l clicanmes failure to ennouet adeaunte-oversicht of - 1
~
esultina in the use of'oroducts or services that are !:ive 'or indeterminate anality and~that have safetv l _nce. i y >
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- h7 cpparent' Koot...causa ? of the . violation or problem?
,j re of the liennees~and the vendnr'(NSSS) to enmnare reanir - nts'withJ the ASME Cada
? W me c2ge that should' be-' given to the licensee' -(and' l j$ through this' enforcement = action.: he's are'resonnaible for the assurance that'vandor
.es are ennducted'in enmnliance with covernina codes hdards.
. i linformation related' to the' following civil' penalty
~
on or mitigation factors (see' attached matrix and [irt 2, Appendix C, Section ,VI.B.2. ) : ,
]
'ITIFICATION: (Who. identified ' the violation? . What - l ! tha fccts and circumstances related to the discovery
- tha violation?" Was -it self-disclosing? Was it 1
1tificd as.a result-of-a. generic notification?) J
- n violation was identified by a racion-based NRC
- inactor while enanarino nrocedure and ASME Code l
iniiramants af ter nh=ervina weldina activities in the
- ild .
lECTIVE ACTION: Although ' we expect to learn more prmation regarding corrective action at the brc: ment conference, describe preliminary information i hin:d during the inspeccion and exit interview. J l imnronerly danosited weld material was removed by l _ndina. nrocedures rewritten.'and welds'nroperly inleted in accordance with the ASM5 Code reauiramants i = wero - the immediate? corrective- actions taken upon .
- ovary :. of - the ; violation,- 'the development and -]
- .ementation of long-term corrective action' and the ;
glinaco of corrective ~ actions?- J l .~1adiate work"sto_nnace until'4mmmadiate corrective ainna were'en=nlated; Problem renort'initated. 4 ~ c )
'I
. ., n
- i What was the . degree of licensee initiative to address the violation and the. adequacy of root'cause analysis?. 1
'The violation was' discovered on a Saturday afternoon. .1 l
A sianifiraant niunhar of licensee oarsonnel worked J throuah the weekend to determine the scone and cause of l f'i the eroblem(s1 and to start recoverv. l
- c. LICENSEE PERFORMANCE: This factor takes' into account the last two years . or the period - within the last , two i inspections, whichever is longer, List past violations that may.be related to the current t i violation (include specific requirement cited and the date issued) : ,
i . 4 J None identified , Identify the applicable . SALP category, - the 4 i rating. for this category and the overall rating for the last two SALP periods, as.well as any trend' indicated: Salo Period Ena/TS Maint/Surv Nov 1. 1990 - May 2, 1992 1 'l May 1, 1999 - Oct 31, 1990 1 2
- d. PRIOR OPPORTunlTY TO IDENTIFY: Were there opportunities for the licensee to discover the violation sooner such as through nonnal' surveillances, audits, QA activities, specific NRC or industry - notification, or reports by employees?
The weldina crocedures went throuch smiltiole reviews by vendor and licensee technical staffs. l l o E .
>~ (..- 3
- g. _ . ~ .
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PIPLE QCCURRENCES: Were there multiple examples of violation identified during this inspection? If -r0 were, identify the number of examples and briefly
- ribe each one.
ne NOV lists three evamnles of instances where ASME - e reouiramants were not oronerly included in the work cedures. _,The first avamnle is the imnroner weld .ctrode size for the temnerina head weld coeration. second evamnle is the 4mnroner location of rmocouoles recuired to monitor the oreheat and ernass' tamneratures . The third eynmnle is the removal tamnorarv' attachments without markina their location , subseouent NDE evamination. ATION: How long did the violation exist? 'dina coerations occurred March 12. 1993, violation ntified by NRC on March 13. 1993. l 1 l l 1 AL COMMENTS / NOTES: The vendor. ABS /CE conducted weld ation testina to determine the effect of usina the ze electrod on the temoerina bead weld. The results .. . . . . ...
.gstina were comnleted on Anril 1. 1993. and concluded 3/328 ' diameter electrode temnerina bead lef t the heat base material in an anorcoriate tamnered condition.
CE renort will be included as a cart of the licensee's 1 reoort.
t
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- a. .
i ' I < ENCLOSURE 1
, r < NOTICE OF VIOLATION
'cnd Light' Docket Nos.: 50-389 License No.: NPF-.16 -
IC inspection: conducted on' March 10-17,. 1993,- a NRC requirements was identified. In accordance with- - ' Statement of Policy and Procedure for NRC Enforcement
- CFR Part 2, Appendix C, the violation is listed below:
Part 50,. Appendix B, Criterion IX, as implemented'by_ icnl ' Quality ; Assurance' Report (FPLTOQAR 1-76A), 1 that measures be established to assure that special .
'G,' including welding, be accomplished-in accordance
>11 cable - codes. The American Society of Mechanical 1 nBoiler and Pressure Vessel (ASME B&PV) Code, Section _
16 Edition with-no Addenda, Subsection NB, has been ' cd co-the applicable code for the repair of the St. ~ nit 2 - Pressurizer. Specific . requirements are as . . ASME '- 'B&PV Code Section III, Paragraph 't 4622.11(c) (6)~, requires that the first layer of weld i ' .cl of._a temper bead' repair be deposited using a 3/32 lh diameter electrodes, that-the weld. bead crown be noved by grinding,'and the second layer be deposited ,
.h en 1/8 inch diameter electrode. ' _ l Paragraph NB-4622.11(c) (5) , _ requires that the weld ,'
e.,;on a temper bead repair, plus a band around the
.d .for 'five inches be preheated to a minimum
. tpsrature of 350 'F and a maximum interpass temperature l 450 *F during; welding, monitored by thermocouples and
. :ording . instruments . ;
4 Paragraphs NB-4622.11(c) (5) and NB-4435 (b) require
- i- inanediate area around the temporarily attached
- i irmocouples be marked so the removal area can be ~,
~' -
intified after their removal for subsequent tds0tructive Examination.
' to-the above, on March 13, 1993', effective measures !
-bean' established-to assure that special process of :
.wac accomplished in accordance with applicable codes ;
r inccd by the ' following.
;uirements of ASMB B&PV Code Paragraphs Nos. -[1]
11(c) (6)', [21: NB-4622.11 (c) (5) , [3] NB-lc) (5)', and, NB-4435 (b) were not incorporated or not l
.yTincorporatedninto the instructions'and procedures i
- cccomplishment - of , the temper ? bead repair to four
.zsr.one inch vapor space nozzles. These discrepancies
.qc , ,
- .; }
7 me . 2tccted by the' authors.and all the reviewers-at the Steam Supply System supplier, ASEA Brown abuction Engineering, as well as all the.' licensee's 1, including the St . Lucie Facility Review Group. The it of above discrepancies and oversights was the is 13, 1993, the following violations were identified: tha.second layer of the temper bead repair to all PrcCourizer .one inch vapor space nozzles was citcd with 3/32 inch-diameter electrodes, th3 preheat temperature of a band of only four 120 or less, in lieu of the five inches required, tnd tha. welds was monitored, and th*J temporary attachment thermocouple welds were not Od prior to their removal. .trity Level IV violation (Supplement I) . 6 e em w er - r-
s I ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL PREPARED BY: R. Prevatte NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This information will be used by EICS to prepare the enforcement letter and Notice, as well as the transmittal memo to the Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit (s): 1 Docket Nos: 50-335 -
License Nos: DPR-67 Inspection Dates: July 30 - September 16. 1995 Lead Inspector: Richard L. Prevatte
- 2. Check appropriate boxes:
(X) A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is enclosed. () This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2)
I.C.7
- 4. What is the apparent root' cang of the violation or problem?
Failure to follow procedures (multiple examples - 81
- 5. State the message that should be given to the licensee (and industry) through this enforcement action.
Procedures must be used and followed. If errors exist in the procedures that prevent followino them. the errors must be corrected.
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attache matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.): ;
- a. IDENIlf1CAIl0N: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation?
Was it self-disclosing? Was it identified as a result of a' , generic notification?) 4 or==les ' dentified by NRC. 2 ex==les by licensee. and 2 were ~ se' f-identifyina.
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview. . ,
lage orocedure chanaes made. norsonnel disciolined. and licensee , strivina to improve standards and nerfomance. ; What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-tem corrective action and the timeliness of corrective. actions? ! Promet action taken each event. , What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis? l This is a lona term action oroblem.
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): NCV 95-07. Loss SDC - incorrect valve maniculation by operator. VIO 94-22-02. Lockeepina errors. - Identify the applicable SALP category, the rating for this category and the overall rating for the last two SALP periods, as well as any trend indicated: Doerations 1 kocent events indicate neantive trend. ,
- d. PRIOR.0PPORTUNITY TO IDENTIFY: Were ther6 opportunities for the licensee to discover the violation sooner such as through normal surveillances, audits, QA activities, specific NRC or industry notification, or reports by employees? .
59 i , i
. e. MllL"IPLE OCCURRENCES: Were there multiple examples of the I violation identified during this inspection? If.there were, identify the number of examples 'and briefly describe each one.
8 ex= ales. see attached violations
- f. DURATION: How long did the violation exist?
Bl.b . i l l t 4
)
i
-i f
i ADDITIONAL COMENTS/NDTES: ! l 4 I I I i i i i I e I l
?
I I l k s i i I i
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i 4 i I a- ' .i J f
'I I
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- , - . =. - - . _ - - - - - ---- ---- - --- - - _ - _ - - _ . - ._ - - - ~
e e l l ESCALAYl0N AND MITIGATION FAC70as (57 Fa 5791, February 18, 1992) '
)
IgENTIFICATim E M IWE LIGNEE Pale IRA.TIPLE stSATIM , ACTION PERPtWIAum WPWTimITY 10 armeasurws IgENTIFY
+/. Sim +/ SOE +/ 100s + 1001 + 100E + 100E ; ! Licensee Timeliness of current Licensee should Multiple used for I identified (M) corrective violation is an have identified examples of significant l l
(To be applied action (M) footsted vlotation violation regulatory even if Epid NRC have failure that is sooner as a identified message to ticonsee could to intervene to inconsistent reeutt of prior during Licensee. (E) have accomplish with licensee's opportunities inspection
; identified the satisfactory good such as audits (only for SL I, ! violation short term or performance (M) (E) II or ill sooner) remedial action violations) (E) ,
(E)) ' NRC identified Promptly Violatloa is opportunities OYNER COWt1DERATIONS (E) developed reflective of avaltable to schedate for licensee's poor discover 1. Leget aspects and potentist
; long term or doctining violation such titigation risks corrective performance (E) as through -
i action (M) prior 2. Nestigence, careless dis-notification regard, .wittfulness and (E) management involvement l self. Degree of Prior Esse of earlier 3. faenomic, personal or l ? disclosing Licensee performance and discovery (E) corporate gain
. (M 25% ff initiative (M) effectiveness j
- 4. -Any other regulatory ~ free .
l there was [To develop of previous 4 initiative to corrective corrective work factors'that need:to be identify root actions and action for sensidereds pending.actlert , cause) root cause) slaltar with regard to ticonsing, vlotations samstasian aseting, or press ; conference. , Licensee Adequacy of the SALP - Period of time
- identified as root cause Considers between 5. What la the intended message a result of analysis for SALP 1 - (M) violation and for the Licensee and the generic the vlotation SALP 2 - (0) notification indastry?
notification (M) sALP 3 - (E) received by , (M) Licensee (E) . . .. . . . . . . If0TES a- * ~ ~~. Comprehensive Prior similarity corrective enforcement between the i action to history violation and prevent inetuding notification i occurrence of escalated and (E) similar non escalated violation (M) enforcement , lamediate Level of corrective management d action w t review the taken to notification restore safety received (E) l and comptionce s (E) i M : M SAFETY SIGNIFICANCE In determining the safety sienificance of a vlotation in conjunction with the enforcement process, the evolustion should consider the technical safety significance of the violetten as well as the regulatory significance. Consideration should be given to the metter as a ediole in light of the circunstances surromding the violation. ' There may be cases in which the technical safety significance of the matter is low while the process controt failure (s) may be significant, and, therefore, the severity Level determination should be based more on the process control failure (s) than on the technical safety issue. The following factors should also be considered: 1) Did the violation i actually or potentially lapact piht te health and safety? 2) What use the root cause of the vlotation? , 3) la the violation an isolated incident or is it indicative of a programmatic breakdown? 4) Wes i management euere of or involved in the violation? 5) Did the violation involve willfulness? ( l
. _ ~ . _____._ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
4 cl Proonsed Violation A l Technical Specification 6.8.1.a required that written procedures be , established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February l
'1978. Appendix A, paragraph 1.d includes administrative procedures for l procedural adherence. Procedure QI 5-PR/PSL-1, R a 62, " Preparation, -
l Revision, Review / Approval of Procedures," Section 5.13.2, stated that l j all procedures shall be strictly adhered to, ,
- Contrary to the above, the following examples of procedural noncompliance were identified: -
; 1. OP 1-0030127, Rev 68, " Reactor Plant Cooldown - Hot Standby to Cold Shutdown," required, in part, that operators block Main Steam
. Isolation System (MSIS) actuation when block permissive
- annunciations were. received. ONOP l-0030131, Rev 60, " Plant Annunciator Summary," required that, upon valid receipt of. '
annunciators Q-18 and Q-20, operators immediately block MSIS i channels A and B, respectively. Contrary to the above, on August 2,1995, during a cooldown of St. - Lucie Unit 1, operators failed to establish the required MSIS blocks, resulting in A and B channel MSIS actuations.
- 2.- OP l-0120020, Rev 72, " Filling and Venting the RCS," precaution 4.2, required that Reactor Coolant System (RCS) venting, described in the procedure, not be attempted if RCS temperature was above 200*F.
, Contrary to the above, on August 2,1995, Reactor Coolant Pump
- (RCP) seal venting, performed in an attempt to correct seal
- package leakage in the IA2 RCP in accordance with Appendix E of the subject procedure, was performed while RCS temperature was approximately 370*F. As a result, design temperatures of RCP seal components were approached or exceeded.
- 3. OP l-0120020, Rev 72, " Filling and Venting the RCS " Appendix E,
- " Restaging Reactor Coolant Pump Seals," required the use of RCP
- seal injection while restaging was attempted.
Contrary to the above, on August 2, 1995, restaging of the IA2 RCP seal package was attempted without seal injection aligned to the seal package. As a result, design temperatures of RCP seal components were approached or exceeded.
- 4. OP l-0010123, Rev 99, " Administrative Controls of Valves, Locks, and Switches," step 8.1.6, required, in part, that all valve position deviations be documented in the Valve Switch Deviation Log.
Contrary to the above, on or about August 1, 1995, HCV-25-1 through 7 were repositioned and left in the closed position e
~~
without the' required entries being made in the Valve Switch ' Deviation Log. The valves' positions exacerbated a loss of RCS inventory.
- 5. OP 0010129, Rev 24, " Equipment Out-of-Service," step 3.2, rsquired that all equipment required by Technical Specifications be logged ,
in the Equipment Out-of-Service Log when determined to be. inoperable. Contrary to the above, inspections performed on September I and 2, 1995 identified inoperable equipment, required by Technical . Specifiutions, which had not been placed in'the Equipment Out-of- !
. Specifically, Unit 1 Containment Purge Valve FCV :
Service 4 and the Lc"IB Emergency Diesel Generator Fuel Oil Transfer Pump , were both inoperable without being entered into the Equipment Out- , of-Service Log.
- 6. OP l-0410022, Rev 22, " Shutdown Cooling," step 8.3.7, required that V3652, the B Shutdown Cooling (SDC) hot leg suction isolation valve, be locked open while placing the B~SDC loop in service.
Contrary to the above, on August 29, a control room operator failed to place V3652 in a locked open condition while placing the B src loop in service. As a result, the 18 Low Pressure Safety Injtetion Pump was operated with its suction line isolated.
- 7. QI 16-PR/PSL-2, Rev 1, "St. Lucie Action Report (STAR) Program,"
required that STARS be initiated for Quality Assurance audit findings and independent technical review recommendations. Contrary to the above, a STAR was not generated when a Quality l t Assurance review of an inadvertent Unit I containment spraydown, 1 documented in interoffice correspondence.JQQ-95-143, identified j j the practice of pre-lubricating FCV-07-1A, Containment Spray hea.ar A flow control valve, when performing valve stroke time 4 testing, i
- 8. ADM-08.02, Rev 7,'" Conduct of Maintenance," Appendix 5, step 5,
- required that procedures be present during work and that individual steps be initialed once performed.
t Contrary to the above, inspection of work in progress revealed ! that individual steps were not initialed upon completion for work ! conducted in accordance with Plant Change / Modification 11-195. This is a Severity-Level III violation (Supplement I). i i (-
,-4.
\
l FXCERPTS FROM IR 95-15
- 3) RCP Seal Failure l
Background
St. Lucie employed Byron-Jackson RCPs and seal packages. The 1 packages consisted of 3 primary seals and a fourth vapor seal.' The primary seals acted to break down RCS pressure in 3 equal stages of approximately 750 psid. The seal stages segregated the seal package into 4 cavities, the lower (below the ' ower seal), the middle (between the lower and middle seals), the : upper (between the middle and upper seals), and the controlled bleedoff (between the upper and vapor seals). Each seal was ' rated for full RCS pressure. The pressure breakdown process resulted in a controlled bleedoff flow to the VCT of approximately I gpm per pump. Seal injection into the lower seal cavity was possible via the CVCS system, however, the licensee discontinued routine use of seal injection in 1993 1 (via safety- evaluation JPN-PSL-SENJ-93-001) following indications that the cooler injection water led to damage of RCP shafts. The seals were cooled and lubricated 'by controlled bleedoff flow which was cooled by a combination of
, the thermal barrier heat exchanger (below the seal package) and a seal water heat exchanger (which cooled flow rising from the RCP casing driven by an auxiliary impeller affixed to the pump shaft).-
Seal Failure On August 2, while performing a Unit I heatup following
. Hurricane Erin, operators noted that the middle seal cavity of the IA2 RCP indicated a pressure which approximated RCS pressure, indicating a failure of the lower seal of the 4
package. Operators subsequently entered ONOP l-0120034, Rev , 34, " Reactor Coolant Pump," which required, upon identification of a failed seal, that seal parameter data be recorded every 30 minutes to ensure that additional seal stages were not degrading. _Throughout the day, the licensee considered the option of
" restaging" the seal package. The process involved opening vents associated with each seal cavity in an effort to
. increase the differential pressure across each seal stage which, in principle, would force moving and stationary seal faces together more tightly, thus reestablishing the seal.
The evolution was described in OP l-0120020, Rev 72, " Filling and Venting the RCS," Appendix E, " Restaging Reactor Coolant Pump Seals.". According to various personnel in the licensee's Operations organization, the process had been successfully applied several times in the past. The licensee opted to perform the , 4 procedure, and informed the inspector of their intentions. 4
-- e- -eg- mum , y , - - , - , - - - - m- , -
The inspector was not familiar.with the process; however, in discussions with the licensee, the inspector was informed that 2 the process had been performed satisfactorily in the past,
- that .a procedure existed for the process, and that experienced ANPSs, who had performed the procedure in the past, were being i
assigned to the task. ~ At 5:17 p.m. on the same day, the licensee began the restaging process. Plant conditions at the time were Mode 3,1450 psia, I 370*F, with RCPs in operation. Per the governing procedure, i the controlled bleadoff cavity was vented, followed by the upper and middle cavities. At this point, flow out the vents
; was expected to decrease as the lower seal stage restaged; L , however, flow did not diminish and, after approximately 1 minute, black material was noted to be in suspension in the vented reactor coolant from the middle cavity. Additionally, the water temperature was noted to increase rapidly.
i Operators closed the middle cavity vent valve and noted that, 4 almost immediately, black, hot, water issued from the upper
- seal cavity vent, indit
- ating a middle seal failure. Operators
- inmediately closed the vent valves associated with the upper seal cavity and the controlled bleedoff. cavity.
s ] , At 5:50 p.m., control room ~ differential pressure indications were received which confirmed that both the lower and middle seal stages had failed. Controlled bleedoff flew increased to
- greater than 3.5 gpe., which indicated degradation of the upper seal. At 6
- 10 p.m., a cooldown and depressurization of the unit commenced. At 6:40 p.m., the IA2 RCP was secured and lower seal cavity temperatures were noted to increase to 300*F 4
due to the increased leak rate through the seal package and the lack of auxiliary impeller-driven cooling (as a result of securing the pump). A. MSIS Actuation As the cooldown proceeded, SG pressure decreased and, at approximately 700 psig, annunciators Q-18 and Q-20, "MSIS Actuation Channels A/B Block Permissive," illuminated. These were expected alarms, as cooldowns d i ! naturally result in SG pressure decreases below the MSIS setpoint. MSIS block keys were provided for this eventuality to prevent MSIS actuations under non-accident related conditions of low SG pressure. The desk RCO, who was performing cooldown-relsted duties at the subject area of the control panels, acknowledged the annunciators and later reported observing that the MSIVs and MFIVs were in their post-MSIS positions as a , function of the cooldown. Consequently, the RCO elected i not to insert the MSIS block and returned to VCT i degassing operations. The RCO was then questioned by an 1 2 i
, j
- . - ,
- e . - . . . . -- -- . w. - . , . . - . . . - - . - - -,
1 , STA as to the failure to' block the MSIS. The RCO responded that, as the MSIVs and MFIVs were in their post-trip positions, the actuation would not present a problem. The board RCO (the second of the two RCOs 1 performing the cooldown) ~ became involved and directed l that the MSIS be blocked. Before the keys could be inserted to block the signals, SG pressure fell below the actuation setpoint and an MSIS was received. The signal was later blocked and reset. The inspector reviewed HPES 95-07, Rev 2, the licensee's 4 review of the event. In it, the licensee determined that, in " Summary of Factors that- Influenesd Human Performance," the event was the result of a lack of knowledge on the part of the desk RCO that an MSIS was , reportable to the NRC whether or not components changed ' state. Under " Summary of Causes," the licensee cited
~ the following causal factors:
- Training / Qualification:
The licensee determined that training had not educated operators as to the reportable nature of - ESF actuations, whether or not components changed state.
- Supervisory Methods . Progress / Status of Task not Adequately Tracked:
The licensee determined that the ANPS and - NPS were too involved in the diagnosis of the RCP seal failures and were not observing the overall cooldown in progress at the time.
- Work Practices -
Pertinent Information not . Transmitted: The licensee determined that the desk RCO did not , announce to the rest of the control room that the annunciators had been received; thus, ANPS/NPS involvement to establish the MSIS block was not obtained.
- Work Practices -
Document Use Practices - Documents not Followed Correctly: The licensee determined that OP 1-0030127, Rev 68, " Reactor Plant Cooldown - Hot Standby to Cold
. Shutdown," contained a step requiring the operator to block the MSIS when the permissive was received; however, the step was contained further into the procedure than the operator had proceeded. Additionally, the licensee determined that the operator had failed to refer to the
, annunciator response procedure, which directed *
[ that the block keys be inserted. 3
% - . - _-- ,m,- - - - - - , _ - - - . - - - - - - - - - _ _ _ _
4 The licensee's proposed corrective actions for this 4 J event included:
- Revising operator training to include "the necessity to block ESFAS and other reportable actuations when they alarm...The plant's operating philosophy of keeping Licensee- Event Reports to a mihinum should also be included and stressed."
I Including the event in Licensed Operator Requalification Training.
- Emphasizing that control room management should maintain a' " big picture" view of plant evolutions, that formal crew communications should be employed, and that procedures are followed.
The inspector. concluded that the licensee's investigation was weak in that:
- The operator's knowledge of procedural requirements prior to the event was not reported (i.e. did the operator know that the OP 1-0030127 required that the MSIS be blocked?).
i
- The conclusion that' the operator's lack of 1 knowledge of the reportability of the MSIS
, actuation was a principle contributor to his 4 actions appeared to place more importance on
. avoiding an administrative / visibility burden (i.e. reporting actuations to the NRC) than it did on knowledge of, and adherence to, procedural j requirements.
The inspector discussed the subject report with the ; licensee. Operations management stated that the ' operator in question reported being confused at the time , and that it was their expectation that, under such circumstances, operators would refer to the annunciator response procedures provided for each annunciator panel. Management further stated that it was not their' expectation that RCOs would be familiar with NRC reporting requirements (this knowledge was said to be the responsibility of ANPS/NPSs and STAS) and that operator actions should be based upon procedure requirpments, as opposed to reportability. The inspector reviewed OP l-0030127 and found that step 8.21 directed that "At 700 psia S/G pressure, Annunciators Q-18 and Q-20, MSIS Actuation Channels A/B 4 f m, ,.c ., r,.,.. - 7 . -..._.g . -..,.-.r.
I Block Permissive, will alarm. . Block MSIS by placing MSIS block key switch to BLOCK position." Additionally, ONOP l-0030131, Rev 60, " Plant Annunciator Summary," specified that, upon valid receipt of annunciators Q-18 and Q-20, operators were to immediately block MSIS channels A and B, respectively. The inspector concluded that the failure of the Desk RCO to perform step 8.21 of
-OP 1-0030127 constituted the first example of a violation . (VIO 335/95-15-01, " Failure to Follow Procedures," Example 1).
Following the MSIS, the cooldown was temporarily suspended. At approximately 8:18 p.m., an annunciator was received indicating that reactor cavity leakage exceeded I gps. Operators verified that control room instruments indicated an increased leak rate from approximately .25 gpm to approximately 2 gpm. The leakage was identified as being related to the IA2 RCP vapor barrier. Operators entered ONOP l-0120031, Rev 23, " Excessive Reactor Coolant System Leakage," at 8:24 p.m. At 8:44 p.m., safety function status checks were completed satisfactorily. At 9:25 p.m., the licensee declared an Unusual Event based upon occurrences that warrant increased awareness, specifically, due to concerns over further RCP seal degradation. At 6:30 a.m. on August 3, the Unusual Event was terminated based upon the reduction in RCS leakage through the IA2 RCP seal (due to depressurization) and on stability of plant conditions. The licensee performed a cooldown/depressurization of Unit I and replaced the subject seal package. The failed package was then disassembled. in an attempt to determine the root cause for the failurer. At the close of the inspection period, the licensee had.not concluded its root cause investigation. The inspector discussed the effort with the licensee. The most probable root causes for the noted conditions were described as follows:
- The most probable root cause for the indicated failure of the lower seal was destaging.- Upon restaging, the ;
carbon face of the lower seal was believed to have been I forced,' rapidly, against its mating seal face, resulting l in fracture. j
= The most probable cause for the middle seal failure and
, degradation of the remaining seals was stated to be a reduction in cooling and lubricating flow though the seal as a result of the venting of the seal cavities. The subsequent torque, imposed due to pump rotation i without lubrication, fractured the middle seal rotating i face. 1 Following the failure of the IA2 RCP seal package, the PGM 5
., ._-v-.. , , .
i 4 j l* initiated STAP 950849 to perform a self-assessment of the decision making process that led to the restaging of the seal. 1 i The conclusions reached in the self-assessment were that the . one-on-one nature of the decision making process precluded a s " synergistic environment." The study went on to state that, while several individuals expressed concern over the prospects , for success, no specific technical . issue was raised. The l licensee determined that the existing Nuclear Policy 105 d process, which required multidiciplinary review of proposed
- abnormal activities, should be expanded such that it is
- - employed when questions of procedure applicability are raised.
The inspector reviewed available information regarding RCP !
. seals and restaging. The following was noted:
- OP l-0120020, Rev 72, " Filling and ~ Venting the RCS,"
- contained, in the base procedure, precaution 4.2 which
- stated."Do not attempt to vent if the RCS temperature is !
above 200*F." Initial conditions specified in the base J procedure were consistent with the Cold Shutdown mode of j operation. - 1
- OP l-0120020, Rev 72, " Filling and Venting the RCS," 1
] Appendix E, " Restaging Reactor Coolant Pump Seals,"
- included only two statements that could be construed as initial conditions or precautions. One was in the form i of a note and the other in the form of a caution. The note stated " Ensure seal injection is aligned and in service." The caution s ated "If RCS is greater than t t 200*F, Then use caution when venting."
l
- FSAR section 5.5.5.2 stated that the vapor seal was designed to withstand RCS operating pressure when the 1
- RCPs were idle. !
4
- The restaging process described in Appendix E to OP l--
l 0120020 was substantially the same as the seal package > venting procedure described in the vendor technical manual for the RCP. However, the venting procedure in the technical manual directed that the venting be . perforsed at approximately 200 psi with an idle pump. i
- Safety Evaluation JPN-PSL-SENJ-93-001, Rev 1, " Deletion of RCP Seal Injection," included, by reference, FPL letter L-81-107 to the NRC reporting test results for RCP seals in postulated- station blackout conditions. ;
The results of the tests were that, under simulated Hot ! Standby conditions, a maximum of 16.1 gph was recorded after 50 hou.rs without cooling water flow to the seal 4 package.
- The vendor recommended a maximum seal package 6
^
, i temperature of 250'F based upon the rubber components in 4 the seal package. Safety evaluation JPN-PSL-SENJ-93-001 provided analyses to increase the temperature limit to 4 300*F.
- The licensee produced a Byron-Jackson letter, dated j Noventier 16, .1990, which reported a review of St. )
. Lucie's proposed restaging process. The letter stated 1 that the proposed process was acceptable. The letter 1 also stated that application of the process should i consider initial seal condition and age in determining I whether to apply the ' process.
1 The inspector concluded that the licensee had reason to believe that restaging the IA2 RCP seal package would correct i the identified condition. Vendor information and knowledge of previous successful restagings tended to support the evolution. However, the inspector found that the procedure l appendix which directed the evolution did not require initial ' conditions sufficient to ensure that seal package temperature limitations would be observed. In fact, the " Caution" statement of the Appendix (advising caution if RCS temperature 1 exceeded 200*F) ran counter to precaution. 4.2 of the base l procedure (precluding venting if RCS temperature exceeded i 200'F).- Absent any modifying information in Appendix E, the I inspector concluded that the initial conditions specified in I the base procedure applied to the procedure' and its appendices. Consequently, the failure of the licensee to adhere to the initial conditions specified in OP 1-0120020 is an example of a violation (VIO 335/95-15-01, " Failure to l
; Follow Procedures," Example 2). l The inspector noted that control room logs did not' reflect the alignment of seal injection, while the note of Appendix E of OP l-0120020 required seal injection. When questioned, the licensee stated that seal injection was not aligned due to concerns for the affect it might have on the RCP shaft. When asked why a TC had not been made to the Appendix, the licensee had no explanation. The licensee's failure to align seal injection to the IA2 RCP prior to restaging the pump's seal is
-an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 3).
r The inspector reviewed ONOP l-0120034, Rev 34, " Reactor E Coolant Pump," and found that, while actions were described
, for the failure of one RCP seal (30 minute readings to ensure
- degradation is not occurring - step 7.2.8.C), and more than one RCP seal *(unit shutdown, secure RCP when TCBs open - step 7.2.8.D), no actions were specified for the instance when 3 seals had failed. As stated above, the fourth, vapor, seal was only designed to contain system pressure when an RCP is idle. The failure of 0NOP l-0120034 to direct the securing of 7
~,
)-
i an RCP when 3 seals have failed was found to be in contradiction to the design parameters of. the RCP. The inspector brought this to the attention of the licensee. The l licensee reviewed the issue and stated that PCRs would be prepared for the RCP off-normal . procedures for each unit, adding a requirement to trip the unit and secure the affected RCP should third stage seal failure occur. ] In conclusion, the inspector found that the activities
, relating to the failure of the lower seal of the IA2 RCP were ] poorly considered in that the restaging process was applied in ; inappropriate plant conditions. The failure to establish ! proper initial conditions for the restaging was found to i exacerbate the seal's already degraded condition. The 1 inspector further concluded that two examples of procedural
, noncompliance were associated with the seal restaging effort l noncompliance was and that one example cf procedural
, associated with the MSIS actuation. The licensee's evaluation i of the MSIS actuation was found to be inappropriately focused on event reportability, as opposed to procedure compliance.
4 The licensee's self-assessment of the decision making process ! that led to the restaging of the IA2. RCP was found to be commendable. OP l-0120034 was found to include ! inconsistancies between the base procedure limitations and those found in Appendix E of the same procedure. A weakness was identified in ONOP l-0120034, in that design limits of the RCP seal package vapor seal were not properly incorporated
- into the procedure.
i
- 4) Reduced Inventory for RCP Seal Replacements On August 5,. Unit 1 entered a reduced RCS inventory condition to support RCP seal replacement work. The following items
! were observed during this evolution: ) Containment Closure Capability
~
Containment was , established and maintained during the evolution. The , l equipment hatch had been open prior to draindown, but it i L was replaced, and the personnel hatch closed, once . [ equipment required for the RCP maintenance was in I containment. !
- RCS Temperature Indication - Normal mode 1 CETs were available for indication.
4
. RCS Level Indication - Independent RCS level indications
- were available. ' A Tygon tube level indicating standpipe 4 l in the containment was manned during the draindown and
! was displayed, via closed-circuit television, in the control room. The inspector walked down the tygor, standpipe and verified it to be correctly aligned and l free of obvious kinks which would adversely affect its < 8 q -, r g y
4 e
~
operation. Additionally, a wide range pressurizer level i transmitter provided level and trend indications in the control room.
- RCS ' Level Perturbations - When RCS level was altered, I additional operational controls were invoked. At plant .
j daily meetings, operations took actions to ensure that-j maintenance did not consider performing work that might
- effect RCS level or-shut down cooling.
}
- RCS Inventory Volume Addition Capability - Three 1-charging pumps and a HPSI pump were available for RCS l addition.
- RCS Nozzle Dams - Due to the type of outage, the nozzle dans were not installed this time.
- Vital $lectrical Bus Availability - Operations would not 2-release busses or alternate power sources for work 4
during this evolution. Both EDGs were operable, as were j all offsite power sources.
- Pressurizer Vent Path - The aanway atop the pressurizer E has been removed to provide a vent path.
L The inspector observed control room' activities during the RCS
- draindown to reduced inventory conditions. .The evolution was performed in accordance with OP l-0410022, Rev 21, "Shetdown j Cooling," Appendix A. "Ir.structions for Operation at Reduced
- Inventory or Mid-Loop Conditions," and OP l-0120021, Rev 38,
" Draining the Reactor Coolant System." The inspector verified that specified conditions were met prior to the evolution.
The inspector found that operators controlled the evolution well, that appropriate cross checking between level indications were performed, and that procedural r6quirements l for waiting periods between draining stages were met. The licensee exited reduced inventory conditions following the RCP seal replacements on. August 7.
- 5) Shutdown Cooling Relief Valve Lift A. Background On February 28, while placing the 1A SDC train in service, the licensee experienced a lift of IA LPSI pump suction relief valve V-3483 (see IR 95-04). The valve l did not reseat, and the loss of RCS inventory was abated by closing LPSI hot leg suction isolation valves V-3480 and V-3481, which isolated the relief valve from RCS pressure. The root cause of the lift was determined to
, be water hammer, which resulted from passing relatively hot RLS fluid through the suction line at high velocity 9
m f (
i i.
. i l
~
as the LPSI pump was started. As corrective action, the licensee revised 0P l-0410022, " Shutdown Cooling," to
; change the methodology of starting the LPSI pump to the following:
Shut LPSI pump discharge. isolation and LPSI 4 header isolation valves l
- Start the LPSI pump
- Inmediately open the LPSI pump isolation valve
- Throttle open two LPSI header isolations to 150 gpm per header .
- Run for 15 minutes !
*
- Start the second pump
- Throttle open the remaining LPSI header isolation i valves to 150 gpm per header
- Wait 5 minutes
- Incrementally open header isolation valves to 2- obtain full flow. I I The licensee reasoned that this methodology would result i in a slow increase in flow, allowing controlled system i j heatup and minimizing the mtential for water hammer. I
!' B. LPSI Discharge Isolation Valve Lift On August 10, while placing the Unit 1 SDC system in service to support a cooldown required due to inoperable . PORVs (see IR 335/95-16), ~ V-3439, the A LPSI header . thermal relief, lifted resulting in a loss of ; t approximately 3500-4000 gallons of RCS, coolant in the Unit 1 Pipe tunnel. The following timeline was interviews,
- developed from operator logs and i
instrumentation data: 0018 A LPSI pump start (ANPS, NWE, Logs) Pressurizer level begins to drop (strip chart data) 0025 ANPS directs SNPO to tour pipe tunnel due to i
, minor reduction in pressurizer level (ANPS)
- No increases in HUT, RWT, etc noted (ANPS)
SNPO reports no unusual conditions in pipe tunnel 0105 B LPSI pump start (ANFS, NWE, Log) Pressurizer level recovers and oscillates (strip' chart) 0140 Cooldown flow established (ANPS, NWE) 0210 Fire watch calls control room, reports water l l issuing from watertight door isolating pipe tunnel from RAB (ANPS, NWE) ! 0215 SDC secured (ANPS, NWE) i Pressurizer level increases and stabilizes (strip chart) 0226 Floor drain isolation valves (FCV 25-1 through 7) i 10 l 4
+ - c--;-- se - - - . *% - - - - - -
- ______________________-_._4
s 1 noted to be closed on control panel (ANPS, WE) Drain valves subsequently opened (ANPS, WE) Flooding in RAB ONOP entered (ANPS) Water levels in pipe tunnel weren't dropping due to clogged floor drains. (WE) 0345 Water in pipe tunnel pumped by maintenance personnel to floor drains in RAB (ANPS) Operators cycle various isolation valves looking for leak - 0611 1A LPSI pump started with WE observing in pipe tunnel (ANPS) 0612 WE identifies V-3439 as passing water (ANPS) The licensee concluded that the cause of the relief valve lift was a pressure surge while LPSI pumps were ; operating in a low-flow condition. The combination of RCS pressure (a maximum of 267 psia at the time) and LPSI pump discharge head at essentially no flow (approximately 182 psid) combined with possible perturbations (when starting the pump) was considered enough to challenge the relief valve setpoint (485-515). This condition existed from the time the 1A LPSI pump discharge isolation valve was opened until operators initiated flow through the LPSI header isolation valves. 1 V-3439 was designed to provide a 10 percent blowdown, which, if applied to the lower acceptable lift setpoint of the valve (485 psig), would require a 48.5 psia , reduction in pressure to allow reseat. Given these , parameters .should V-3439 open, RCS pressure would have
. to drop to.436.5 psia to allow valve reseat (assuming only a 10 percent blowdown). The volume of the RCS and pressurizer would preclude such a reseat until significant volumes of coolant were lost.
The volume of coolant lost during the event was estimated by the inspector, based upon floor layouts as displayed on drawings. Given water depths reported by the WE -(up to approximately '14" in some areas), the inspector estimated that approximately 3500 gallons were lost. The CVCS makeup integrator, measuring volume added to the VCT in maintaining pressurizer level- on 8 setpoint, indicated that 4000 gallons were added to the VCT. (
- The licensee concluded that the closed floor drain isolation valves, HCV-25-1 through 7 (a set of 7 ganged valves) were the result of valve stroke testing in
-preparation for Hurricane Erin. During testing conducted by control room operators, some of the valves had failed to stroke properly. As a result, the valves .
- 1 11 1
-j l
7 i j were left closed for- troubleshooting and were never S reopened. OP l-0010123, Rev 99,' " Administrative Control
; of Valves, Locks, and Switches," required, in step 8.1.6, that "All valve or switch position deviations or lock openings shall be documented in Appendix C, Valve 1 i Switch Deviation Log..." The inspector reviewed j
- archived Appendix C logs completed in July and August '
and control room open Appendix C logs and found no evidence that HCV-25-1 through 7 were loggte as being i out of position. The failure to enter the valves
- l closed status into the valve deviation log is an example )
of a violation (VIO 335/95-15-01, . " Failure to Follow J Procedures," Example 4). STAR 950917 was initiated to develop a - PM for verifying that floor drains were unclogged, i !' The lii:ensee prepared an evaluation of the effects of the subject setpoint/bloswn values on plant operation. JPN-PSL-SENP-95-101, Rev 1, " Assessment of the Effects on Plant Operation of. Lifting the LPSI Pump Discharge < . Header Thermal Relief Valve," concluded that the subject i ! condition would not have a significant effect an safe plant operation Juring normal, shutdown, and design basis accident conditions. In reaching this conclusion, the evaluation noted the following: i . As flowrate through the relief valve (at lift setpoint pressure) was approximately 40 gps, the loss of inventory was within charging system capacity (44 gpa per pump). l .
- During the injectbn phase of an accident, the LPSI pumps would draw. suction from the RWT, thus pressure deve!oped by the pump would not compound a 'high pressure suction. source and the relief
~ valve's lift setpoint would not be challenged.
i
- The relief valve in question discharged to a
- floor drain which directed flow to the safeguards room sump. The sump was designed to be pumped L. down in level to the EDT automatically when offsite power is available. Thus, with offsite
- i. power available, no flooding hazard would exist.
Under conditions with no offsite power available. the water level in the safeguards room (after the l sump overfilled) would not rise to the leviel of 4 the HPSI $rJmp motorf until approximately 7 hours after the lift. Before this time elapsed, the licensee reasoned that sump high level alarms would ciert operators to the event, allowing operator intervention prior to the loss of the - HPSI pump I 12 l
-- - ~ . . , _ _.
- The licensee noted that, while SDC was assumed to be placed in service during postulated small j break LOCAs, ESDEs,.And SGTRs (when RCS pressure may have been high enough to have led to a relief
- valve lift), the FSAR analysis demonstrated that fuel damage (and thus the release of significant amounts of radioactive material to the RCS) was
< involved only because of extremely conservative j assumptions. The evaluation went on to state !
that "A review of FSAR analysis of small break l LOCAs, ESDEs and SGTRs demonstrates that these 1
; accidents will' not result in fuel damage .if ) ! assumptions - that reflect the actual operating )
history of the plant are applied. Therefore, the l 1- radiological consequences of these FSAR accidents l will not be increased and the FSAR offsite doses. l remain bounding." i i The inspector took exception to the licensee's 4 conclusion. The subject passage was included in Section 4 of the evaluation, " Analysis of Effects of Lifting V3439," in a section entitled " Increases in Radiological Consequences of Design Basis Accidents." The inspector i
- found 'that, in choosing to neglect design basis 1 4
assumptions in their analysis of- the event l- (specifically, a return to power and fuel failure resulting from the most reactive rod failing to insert), 1 i the licensee did not evaluate the increases in the l i ' radiological consequences of design basis accidents. Rather, the- licensee evaluated the radiological consequences of a less significant set of accidents and concluded, without providing quantitative results, that
~
i the radiological consequences of design basis accidents ' F bounded the notad relief valve lift. While the
. inspector agreed with the licensee's position that the :
circumstances assumed in design basis accidents were, .
- probablistically, of low likelihood, the inspector I
, pointed out that the assumptions were the approved j
- licensing basis of the plant and, as such, provided the ;
appropriate common ground upon which to evaluate the event's significance. The inspector brought this to the l i , !' attention of the licensee, who stated that they would l consider the issue. At the close of the inspection
- period, the licensee had not presented a final position
- i. on the' issue. As a result, this issue will be tracked as an unresolved item (URI 95-15-04, " Adequacy of Engineering Evaluation Regarding Unit 1 Loss of Inventory via V-3439").
On August 12, the inspector requested data on approxtr.ately 25 relief valves on both units which j communicated with the RCS in some way. The requested 13 l
, ~
(-.
data included lift and blowdown setpoints, tolerances, relief capacity, and normal operating pressures l
experienced by the valves. Shortly after requesting the
' information, the licensee informed the inspector that a team had been formed to evaluate all safety-related relief valve data. The team included members from -
Engineering, Maintenance, Operations, Tech Staff, and Licensing. 1 The team's review was documented in JPN-SPSL-95-0334, !
'*St. Lucie Units 1 and 2 Design Review of Safety Related Relief Valves," transmitted to the site by letter dated ;
August 30. The inspector found the methodology of the : study to be sound, considering worst case combinations l of system operating pressures, relief valve setpoint, and blowdown. Relief valves were . evaluated for their margin to lift and blowdown margin (the difference l between reseat pressure and normal system operating
- pressure). The document reported that, of 114 relief
- valves reviewed, 8 valves on Unit I and 5. valves on Unit 1
2 required further review due to unacceptable margins of l ' lift or blowdown. Corrective Actions were specified for :
- the following valves
Unit 1 Valves-
= V2324, V2325, and V2326 - Charging Pump Discharge l Relief Valves - MEP 107-195M was issued to reduce the . design superimposed backpressure from 165 psig to 115 psig.
l
= V2345 - Letdown Relief Valve - PC/M 108-195 i
issued to reduce letdown backpressure to 430 psig 1 and to reduce the valve's blowdown from 25 percent to 15 percent. ! = V3412 - HPSI IB Discharge Header Relief Valve - EP 115-95 was issued to increase the design ( setpoint from 1735 psig to 1750 psig and to reduce blowdown from 25 percent to 10 percent.
= V3417 - HPSI Pump 1A Discharge High Pressure Header Relief Valve -design setpoint increased from 2400 psig to 2485 psig and blowdown reduced
'from 25 percent to 15 percent.
- V3468 and V3483 - SDC Suction Relief Valves -
STAR 950430 was issued to evaluate new setpoints and blowdown values. Unit 2 Valves , 4. 14
* ' - - y ~ ~ , - , + - --m;-_ _ - _ _ _ _ _ - _ _ _ _ . _ _ _ _ . . _ . _ _ . _ _ _ . _ _ _ _ . . - _ . . .
4 a
'V2345 - Letdown Relief Valve - At the close of the inspection period, an EP was being prepared
- to implement actions similar to those implemented on Unit 1.for this valve.
- V3412 - HPSI 2B. Discharge High Pressure Header Relief Valve - At the close of the inspection period, an EP was being prepared to reduce blowdown from 25 percent to 10 percent.
l
- V3417 - HPSI Pump 2A Discharge High Pressure
-Header Relief Valve -
At .the close of the inspection period, an EP was being prepared to increase the valve's setpoint from 2400 psig to 4 2485 psig and to reduce blowdown from 25 percent , to 10 percent. i
- V3439 and V3507 - Low Pressure A and B Discharge
- Relief Valves - At the close of the inspection period, an EP was being prepared to increase the valve's setpoint from 500 psig to 535 psig.
i As a result of the licensee's investigation, and through discussions with vendors, the licensee determined that ' some relief valves had been provided with unacceptably high blowdown values. This ~ was, apparently, due to
- procedural, prcblems at the vendor's test facility. At the close of the inspection period, the vendor (Crosby) ,
was considering the 10 CFR 21 ramifications of the issue. The licensee documented the conditions on STAR 951024. The inspector reviewed the STAR and noted that , ithadnotbeenidentifiedasan"N" STAR (indicatinga noncor. forming condition). The inspector brought this to the attention of QC, and the condition was corrected. The licensee identified the affected relief valves and segregated them appropriately. ! The inspector reviewed the licensee's STAR database for ever.ts similar to 'the subject event and found the
- following
I
- STAR 2-950167, initiated February 20, documented the lifting of SDC heat exchanger CCW relief valve SR-14350 'when stroking CCW "N" header isolation valves closed. Once open, the relief '
valve had to be isolated (by closing an upstream valve in the process line) to bring about a reseat. !
- STAR 0-950234, initiated March 2, documented the
, . fact that relief valves had lifted and that blowdown values placed the resent pressure of the 15 i
-ne
'M valves in the operating ranges of the systems they protected.
L
- STAR l-950269, initiated ' March 10, documented relief: valve lifts on the Unit 1 CVCS letdown :
. line _during evolutions which should not have l challenged the valve's setpoint. ,
l
- STAR 0-950917, initiated August 18, documented !
the subject SDC relief valve lift. ! In addition to the STARS referenced above, IR 95-05-01 , discussed work performed on the Unit 2 CVCS system to prevent letdown line relief valve lifts. The IR also
, described the failure of the relief valve to ressat (once lifted) due to a blowdown value which placed the resent pressure below the system's normal operating
). pressure. 1 - The inspector reviewed the status of the ETARs listed
. above and 'found them all to be open. The inspector i
discussed the timeliness of the resolutions to the .
- subject STARS with the licensee. The licensee stated that their focus had been on the methodologies for
- setting blowdown values on the valves in question, rather than on the appropriateness of the setpoints
, themselves. The licensee offered STAR 950234 as being illustrative of this point.
~
e The proposed corrective ! actions included:
- Completion of SRV test benches, wtiich would allow the licensee to better set and test SRVs for lift :
, setpoint and accumulation. It was noted that the ! i bench had only limited blowdown test capability. - 1 l
- Performing an engineering design basis review of l- all safety related SRVs to validate or correct i 3 setpoints and issue a design document that l summarizes the design data.
- Enhancing journeyman training on SRVs.
While the inspector found the licensee's proposed' i activities prudent, it was noted that nothing precluded engineering from addressing the setpoint issue earlier in the process. The licensee stated that the STAR was addressed in stepwise fashion and that the maintenance-related items were addressed prior to forwarding the STAR to engineering. 4-The ' inspector found that the licensee's corrective
- actions for the subject event were comprehensive and 16 4
. . , - - e- 4 -
e -- , e,,-w --n, , ,w-, n . . _ _ _ . _ _ , _ _ _ . _ . _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
c sound. However, the inspector concluded that _ ths - actions could have reasonably been expected to be performed in a much more timely fashion. The subject phenomenon was identified as early as February,1995, g and repeated itself on no less than 3 separate systems, and on both units, prior to the most recent event. Once i focused on the issue, an engineering product of high i quality was developed, and corrective actions initiated, in approximately 2 weeks and identified valves requiring , attention in a comprehensive action. 10 CFR 50, Appendix B required that, for conditions adverse to quality, prompt corrective action be taken to prevent recurrence. The licensee's failure to take prompt 4 corrective action to the February / March events is a . violation (VIO 335/95-15-02, " Failure to Take Prompt Corrective Actions for Repeated Relief Valve lifts").
- 6) Containment Spraydown A. Background The St. Lucie Unit 1 LPSI and CS systems are shown in '
Figure 1. The two systems are interrelated in that they share the SDC heat exchangers. In an accident mode, the SDC heet exchangers serve to cool water draw from the containment sucip prior to delivery to the containment environment via the containment spray headers. Referring to Figure 1, the accident mode flowpath for CS, train A, involves water _ traveling into the A CS pump, through the SDC heat exchanger, and to the A CS header in. containment. In a SDC mode, the SDC heat
. exchangers, in conjunction with the LPSI pumps, serve to remove heat from reactor. coolant. The flowpath in this mode (again, for the A ttain) involves water flowing from the RCS hot leg and through the A LPSI pump. The fluid flew is then split at FCV-3306, with some water pa:: sed through the valve and the balance diverted through the SDC heat exchangers, through MV-3456 and/or MV-3457, and returned to the LPSI system for delivery to i the RCS cold legs. l During power operations, the two systems are isolated l from one another and each is aligned to perform its safety fun
- ion. In the case of the CS system, this 1 alignahnt involves an open flowpath from the RWT, l through the CS pumps, and up to FCV-07-1A and FCV-07-1B, j normally closed A0Vs which receive open signals in '
' 4 response to a CSAS.
B. LPSI System Venting i In February, the licensee experienced a waterhammer 17 l
O event in the Unit 1 LPSI system while placing SDC in- ' service (see IR 95-04). The licensee determined that one of the potential contributors to the event was air, ! trapped in. system piping. At approximately the same,
- the licensee identified a Unit 2 LPSI pump in an air i
bound condition during a surveillance run of the pump. In response to these events, the licensee developed aggressive venting programs for the systems. As a part 4 of the effort, OP l-0420060, " Venting of the Emergency Core Cooling and Containment Spray Systems," was. develcped. The procedure required, in part, . that venting be performed following SDC system operation.
- The procedure was approved on August 13.
j As a part of the venting procedure, the licensee pressurized the lines leading to the SDC heat exchanger i via the LPSI pumps and systematically directed flow to
- the RWT in an effort to sweep air from the system. The
- boundary of this venting process included the CS lines up to the CS header isolatiorivalves.
C. FCV-07-1A Inoperability On August II, CS flow control valve FCV-07-1A failed a stroke time test and was declared 00S. As shown on i Figure 1, the valve isolated the A CS header from the CS l system outside containment. The valve was designed to
- open on a CSAS and was a fail-open A0V. The valve was
. required by AP l-0010125A, Rev 39, " Surveillance Data Sheets," Data Sheet 8A, " Valve Cycle Test - Non-Check Valves," to stroke in less than 8 seconds. In the failed test, the stroke was recorded as 20.3 seconds. 1 As a result of the failed surveillance test, STAR 950869 l was generated. The stroke time failure was documented l and the STAR was assigned ~ to Engineering for i
- disposition. Engineering proposed placing the valve in ,
its safeguards position (open) and prepared SE JPN-PSL- ' SENS-95-016, Rev 0, " Alternative Valve Position for-
- Spray Header Isolation Valve 1-FCV-07-1A."
The inspector reviewed the subject SE. The purpose of the valve and its relationship to containment isolation and containment boundary integrity were found to be appropriately considered. The SE concluded that no unreviewed safety question was introduced by placing the valve in an open position. The SE went on to provide 3
" required / recommended" actions:
. Administrative controls, consisting of caution tags and the installation of plastic covers over switches, were required to be implemented locally 18 D
.- - . .- . . - . - - -~ - . - . . - . _ - - - . _ - __ . _____ __ - - - _ _ - __ _ ^ '
and at the RTGB for CS pump 1A to prevent inadvertent operation of the pump.
- Operators were to be informed of the new valve alignment with emphasis given to CS pump surveillances and A SDC train operation.
.
- Procedures were to be reviewed for impact. The .
SE stated that, in lieu of procedure changes, ! administrative controls may be used while the .;
. valve was open.
l The SE was approved by the FRG on August 12. Upon completion of the evaluation, the STAR was turned over to Mechanical Maintenance with a required action of restoring the valve to original design and to perform a root cause investigation into the failure. The inspector noted that the subject STAR included no indication that the required. actions listed above had , been completed prior to Engineering releasing the STAR - to Mechanical Maintenance and prior to Operations repositioning FCV-07-1A. The inspector questioned the STAR coordinator as.to who was responsible for ensuring that the SE's required actions were complete and was , informed that Engineering, as the organization I responsible for the resolution, was responsible. The same question was posed to the Engineering Chief Site Engineer, who stated that the responsibility for completing the action belonged to Operations. The inspector reviewed QI 16-PR/PSL-2, Rev 1, "St. Lucie Action Report (STAR) Program," and found that the
. procedure was unclear as to who was responsible for
, ensuring the activities were completed. As a result the
- inspector concluded that a weakness existed in the STAR ,
program with regard to ensuring that required corrective actions were documented and completed. On August 15, a Night Order was issued which informed , operators that the unit would be operated with FCV-07-1A open. The Night Order went on to state "See attached Engineering evaluation which includes actions to be taken to avoid an accidental spraydown of containment." ' The SE limited its consideration for the potential of inadvertent spraydown- to inadvertent CS pump starts, except as provided in the second required action summarized above. On August 16, caution tags were hung ; and the valve was taken to an open position. D. Containment Spraydown On August 18, venting of the LPSI A train was commenced , per OP l-0420060, Rev 0, " Venting of the Emergency Core 19
R
-O Cooling and Containment Spray Systems." When the A train was pressurized through the SDC heat exchangers, the open flow path created to the A CS header through FCV-07-1A allowed water to be drawn from the RWT and passed into the containment atmosphere via the spray header.
Operators were alerted to the event by an ante.nciatoi- i indicating high reactor cavity inleakage. Indicated l flow into the cavity was . increasing rapidly and operators entered ONOP l-0120031, Rev 23, " Excessive Reactor Coolant System Leakage."- Approximately one minute after the annunciator was received, operators identified the flowpath leading to the spraydown and secured the A LPSI pump. The spraydown resulted in a slight decrease in containment temperature and pressure. The licensee noted that 90 percent of containment smoke detectors alarmed or faulted and an electrical ground developed in the IA2 SIT sample valve as a result of the event. - E. Impact on Unit 1 The licensee determined that approximately 10,000 gallons of water from the RWT was transferred to containment during the event. The water was borated at approximately 2200 ppm. The spray resulted in an l increase in contamination ! with levels exceeding lx10'dps/100 levels cm' inside in many containment, areas. Following the event, the licensee placed a hold on all work on Unit 1. The unit was maintained stable in Mode 3 and management announced' that it would conduct a series of meetings with all plant personnel to discuss the recent events on Unit I and to reiterate management expectations for worker performance.. Meetings were held on August 18 in which the Division President, the Site Vice President, and the Plant General Manager stressed the need for worker vigilance, procedural compliance, 4 and a qu2stioning attitude on the part of all plant personnel. Additionally, plant management made plans to cool down Unit I to allow for a decontamination of 4 containment, a repair of FCV-07-1A, and a number of other work items prior to returning the unit to service. l The licensee's initial plans for containment cleanup did , not bring the contamination levels to pre-event conditions. After discussions with management, a decision was made to expand the scope of this cleanup and decontamination to reduce the need for additional cleanup during the next refueling outage. 20
e l The inspector toured the containment on August 19. HP ~ briefings prior to entry indicated that the majority of
- the contamination was in a smearable form. Containment cleanup had begun, and guidelines had been developed and promulgated under LOI-HP-23 " Decontamination Following
, Inadvertent Spraydown of the Unit 1 RCB." The inspector noted that the 62 ft. elevation of containment had been separated into quadrants for initial decontamination. While light water spotting was noted on the outer surfaces of some equipment, no obvious boron deposits were identified. Water was observed to be puddled in upturned I-beams supporting floor. grating, but floor surfaces were dry.
~
The 1icensee evaluated the event in Engineering Evaluation JPN-PSL-SENS-95-017, " Assessment of Inadvertent containment Spray Event." Items considered in the evaluation included:
- Boric acid corrosion of carbon steel components, potential effects on EQ and _ non-EQ instrumentation and electrical equipment.
.. Potential effects on cranes and supports
- Potential effects on snubbers
- Potential effects on containment coatings a
Corrective actions resulting from the evaluation included a comprehensive inspection of components inside containment. Included were visual inspections of all snubbers inside containment following contair. ment washdown for decontamination. The inspection list compiled by engineering included items to be inspected by tag, number, the type of inspection to be performed, acceptance criteria, and actions to be performed if
, acceptance criteria was not met. In all, approximately 1000 individual inspections were performed. Of the items . inspected, only minor deficiencies were identified.
l 1 F. Evaluation of the Licensee's Activities The inspectors concluded that the root cause of the containment spraydown event was a failure of OP l-0430060. Rev 0, " Venting of the Emergency Core Cooling and Containment Spray Systems," to require a verification of initial conditions. Specifically, the ' procedure failed to verify that the CS system was in an
,. alignment which was appropriate for the evolution being' conducted.- The procedure was revised to remove the 21 4
9 s
<_ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ . _ _ _ _ _ _ _ ~ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ . _ _ _ _
4 j subject portion, leaving only static venting, on September 1. The licensee reached a similar conclusion in LER 335/95-007, and added that contributing factors included operators failing to realize that plant i conditions at the time of the evolution would result in : the event. Additionally, the licensee identified that ] the decision to defer the repair of FCV-07-1A
; contributed to the event. The failure to include appropriate initial conditions in OP l-0430060 )
constitutes a violation (VIO 335/95-15-03, " Inadequate l
- Procedural Initial Conditions").
The inspectors reviewed the licensee's corrective actions as they related to containment inspections following the. event. The inspectors found that the licensee's evaluation of the event and the inspection
, scope resulting from the evaluation was in agreement i with the NRC position on the-subject (as c.escribed in 1
the NRR DST Safety . Evaluation on the subject, , transmitted to. regional offices via letter from T.E. Murley.on March 13,1991). The licensee's inspection was determined to be comprehensive in scope and detail i and adequate to ensure future component reliability. ' l 7) Primary Water Storage Tank Overfill , On August 19, at approximately 5:30 p.m., the Unit 1 RCO 4 directed the SNPO and ANPO to fill. the PWST. At approximately i , 7:45 p.m., the " Primary Water Tank Level High/ Low" alarm annunciated in the control room. The RCO directed the SNPO to have the ANPO secure the fill valve to the PWST while making
. his rounds. The decision to delay securing the valve was based on the RCO using a tank strapping table in the control j room which showed a margin of approximately 1.5 feet from the
- high level . alarm to tank overflow. At 8
- 30 p.m., a call was received from the Unit I containment ramp that the PWST was overflowing. At that time the ANPO and SNPO were directed to ,
immediately secure from filling the PWST. The fill valves 4 were then closed. It was estimated that about eleven thousand
- gallons overflowed form the tank. Chemistry samples found ,
, that no release limits were exceeded as a result this event. The cause of this event appeared to be inappropriate and untimely operator response to an alarm coupled with an I existing operator work around on the level control system for the PWST. The PWST level control valve LCV15-6 had a history of ' unreliability. Because of this unreliability, the operator had been manipulating V15106 or V15105 which are in series with LCV15-6. If this condition had been corrected, the-system would have been able to automatically maintain PWST 22
t l 1evel.
- 8) 2A Heater Drain Pump Trip )
, At 8:20 a.m., on August 23, the "LP h ater 2-4A Level Hi/Lo"
- annunciator alarmed in Unit 2 control room. The operator i observed that 2A condenser back pressure had increased from
- 4.5 to 4.9 inches Hg. Immediately thereafter, the 2A heater l drain . pump tripped. The control room operator immediately ~
' entered DNOP 2-0610031, Rev 13, Loss of Condenser Vacuum, and began reducing power to maintain condenser back pressure to
- . less than 4.0 in Hg. Power was reduced and the unit was
! stabilized at 82 percent. The inspector responded to the control room and observed this power reduction. An investigation of the event by the licensee found that relay 63X-4A (a GE HGA relay), common to both the 4A alternate and SA normal heater drain valves had failed. This failure caused the 4A alternate drain valve solenoid to de-energize and the valve to fail open. It also caused the 5A normal drain valve
-to fail closed. These failures resulted in a rapid decrease in level in the 4A heater and tripped the 4A heater drain ,
pump. The inspector found that operators response to the event was timely and correct. The failed relay was subsequently replaced. - An investigation by the licensee determined that the relay failure was due to aging. A review of other applicable uses of this type relay by the licensee found and replaced several other HGA relays in the heater drain system. , The inspector noted that at least eight other heater drain pump trips had occurred over the past two years. None of these trips were the result of a HGA relay failure. The licensees' review of this and other recent HDP trips led them to install a PC/M in the heater drain pump protection circuiting during this outage that should result in a reduction of these and similar HOP trips. The inspector found that the licensee's corrective action for this event wa's detailed and thorough. However, taking into consideration the previous number of HDP trips that had . occurred and the licensee's knowledge of this problem and the needed changes clearly indicate that corrective action on this item was not' timely. This item is identified as a weakness in corrective action.
- 9) Control Room Logs On August 24 during a review of the Unit 2 control room RCO log, the insp,ector noted an entry which stated that 2B EDG had erratic load swings during- the performance of the monthly 23
i l l
' surveillance tests. Further review of the log indicated that i the EDG was taken out of service to replace. an air start solenoid valve and then tested and returnd to service. The RCO, on the shift after this item occurred, was questioned on L the entry involving the erratic load swings and was not aware of the cause or any corrective action taken on this potential deficiency. This ites was discussed in detail with the system engineer who was able to satisfactorily address this ites.
AP 0010120, Rev 74, " Conduct of Operations," section 2.A.3,. j requires that problems associated with major equipment be logged. The inspector noted that the control room log should have contained adequate information to allow the operator on a succeeding shift to clearly understand this potential problem and know if it had been adequately addressed to ensure l operability of this ESF component. In addition to the above, on September 1, a review of the Unit 1005 log found that containment purge valve FCV-25-4 had PW0s 95013857 and 95004327 and STAR 94110479 issued against it. The valve had been placed in the failed closed position but l had not been entered in the 005.10g. OP 0010129, Rev 24, l l
" Equipment Out of . Service," section 3.2, required that i inoperable TS equipment that is out of service be logged.
L Upon identification by the inspector this item was entered in
- the 005 log.
On September 2, the inspector noted that clearance 1-95-009-1 011 had been issued to deenergize IB EDG fuel oil transfer pump to permit work on a local switch. A review of the DOS 1 log and control room log also found that this had not been entered in either as required by the clearance procedure OP 0010122 step 5.6.5. A discussion.with the RCO revealed that , he did not think this entry was necessary since the EDG was out of service for other maintenance activities. This item was discusself with the ANPS who directed that the appropriate log entries be made. 3 The inspector noted that all of the above items were in a safe i condition and did not affect system operability. These items do indicate a weakness in logkeeping that could result in
, operating the plant with equipment out of service that could -
be required for that operational mode. This item is identified as a weakness in logkeeping and a failure to follow I
, procedures,'and is an example of a violation (VIO 335/95 4 01, " Failure to Follow Procedures," Example 5).
- 10) Operation of IB LPSI Pump with the Suction Valve Closed On August 29, Unit' I was in mode 5 with both trains of SDC in operation. At 2:20 p.m., the B train of SDC was placed in
! standby to allow a SDC hot leg suction valve leak test to be 1 24 k
h
, ,n .m.
o. performed as specified in data sheet 25 of AP 1-0010125A. Step 6.5.4.B of this test left one hot leg suction valve V3651 , open and the other hot leg injection valve closed at the ! , completion of the test. The SDC normal operating procedure OP 1-0410022, section 8.3, was then used to return the B train of
- SDC to . service. Instead of using the procedure, the RC0 1
! transposed the procedural steps of section 8.3 to a separate l
- piece of paper and used this to perfonn the procedural steps.
Using this guidance he failed to open and lock open B hot. leg-suction valve V3652 as required by procedure step 8.3.7. T'he IB LPSI pump was then started by the board RCO who noted the starting surge on the pump ammeter and that the amperes had subsequently declined and steadied out at about 15 amperes. The ANPS opened the LPSI discharge valve at the CRAC panel to re-establish flow in the B LPSI loop. . The board RCO did not recognize that LPSI pump B amperes were lower than anticipated. The board RCO then went to the CRAC panel to initiate flow to B SDC HX. At about 4:45 p.m., the NPS identified that LPSI pump amperes were lower than anticipated. At the same time the desk RCO found that the hot leg suction valve V3652 was shut. The IB LPSI was secured and the IB SDC train was returned to the standby lineup. A subsequent inspection of the pump determined that no. apparent damage had occurred during the short period of pump operation. After an inspection and evaluation the pump was returned to service and all parameters were normal. An ASME Section XI test was subsequently performed satisfactorily. The failure of the operator to follow OP 1-0410022 is an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 6). This failure could have resulted in J the failure of the IB LPSI pump and subsequent loss of one loop of SDC.
- 11) IB Emergency Diesel Generator Failure On August 31, the IB EDG tripped due to high crankcase pressure in the 12 cylinder engine during the performance cf the monthly surveillance test, OP 1-22000508, "1B EDG Periodic Test and Gendral Operating Instructions." Licensee personnel found that the engine coolant expansion tank had drained and the engine oil sump level had increased approximately eight inches above normal.
Inspection by licensee personnel revealed that the nuaiber nine , power pack crown and cylinder head had sustained severe damage, apparently due to separation of the northeast exhaust ; t valve head from its stem. The failed valve head became loose within the combustion chamber and during numerous strokes 25
punctured the piston crown and cylinder. The engine coolant
. then leaked through the cylinder head and piston into the oil and entered the engine sump. The source of the high crankcase pressure trip was a combination of intake air and exhaust
. gases escapiog through the failed piston into the crankcase.
The licensee developed a root cause investigation team composed of personnel from mechanical maintenance, technical staff, site and corporate engineering, and ar engine vendor 4 representative. This team performed a detailed Investigation over several days which concluded that the most probable root 1 cause was: '
- Cylinder number 9 lash adjuster lock nut loosened. The lash adjuster screw was then 'able to back out of 1
[l 4 position due to normal operational vibration.
- As the lash adjuster screw loosened, the hydraulic
- lifters initially compensated for the increased height
- of the valve bridge assembly. Eventually the increased height of the valve bridge resulted in impact loading at 1 the locking ring in the lower spr.ing seat. The locking ring is normally unloaded during operation.
l
- The impact loading eventually caused the bridge guide to i fail. This allowed further bridge movement and loss of "zero lash" in- the velve train.
The increased 1 ! clearances resulted in impact loads being transmitted to l the valves themselves. The bridge guide failure also l j increased wear on the guide's lower spring seat.-
- The impact loading caused the lock grooves of both east
! valve spring stems to deform due to fretting wear from i the valve sprin, seat locks. The northeast valve spring i seat eventually failed due to hoop stresses induced'by i the wedging action of the seat locks. i
- The failed spring seat was retained by the helical spring coil which initially prevented valve stes
! detachment. The additional clearances provided by the i failed spring seat allowed the seat locks to progressively fail.due to wedging and point loads until t they finally released the valve and allowed it to drop into the engine cylinder. !
- The . valve head separated from the stem due to impact
- loading by the piston. . The separated valve head was then loose in the cylinder and punctured the piston j crown and the cylinder head when the piston rose.
- Engine tripped on high crankcase pressure due to flow of l turbocharged inlet air and exhaust gases through the 26 i-i
_ ~ , -
piston into crankcase. Water from broken cylinder head water passages flowed through the piston into the
- crankcase to drain the expansion tank. Smaller ,
particles from the piston and cylinder head were blown into the exhaust ducting. The inspector conducted daily meetings with the manager of the root cause team and discussed the status of their
- investigation and findings. He also observed numerous facets l of the licensee investigation, inspections, and repairs to the 4 affected diesel engine.
l The initial p'lans called for replacement of the number 9 power pack (cylinder and piston) and inspection of all shaft i bearings. After inspections found several metal parts from the damaged number 9 cylinder in the exhaust ports of other cylinders and on the engine exhaust turbocharger intake screens, the engine inspection was expanded to include all cylinders, exhaust headers, and bearings. This inspection
- found some rust in number 12 cylinder and led to replacing that power pack also. The inspection of the remaining cylinders also led to replacing number 3 and 4 cylinder heads i due to leaking valves.
! After the above repairs and bearing inspections, the engine was reassembled and flushed with new lubricating oil and all filters were replaced. As a result of the root cause investigation the lash adjuster locking nuts were torqued to a 50 ft-lbf value given by the EDG service company (this value had not been previously specified in the vendor manual or licensee maintenance procedures). This torquing was accomplished on all cylinders for both the 1A and IB Unit 1 i- diesel engines. After a series of maintenance runs and adjustments on September 5 and 6, the IB EDG successfully i-completed its surveillance test and was declared operable on September 6.
- The inspector found the root causes investigation team to be composed of well-qualified individuals. They pursued the issues associated with the failure in a diligent manner and
- worked well with the personnel performing engine repairs. The inspector noted that the licensee's service vendor plans to
- also perform a root cause investigation of this failure.
The inspector was very impressed with the teams that worked the engine repairs around the clock. Their detailed i investigation resulted in expanding the scope of inspection and repair to cover the entire engine. The overall repair effort was strongly supported by site and corporate engineering and r(sulted in timely completion of the repairs. 3: , l
- 12) Unit 2 Main Generator Hydrogen Overpressurization ;
i 27 I I
i f. On September 7, at'approximately 1:30 a.m., a NPO noted that
- - the hydrogen pressure on Unit 2 generator war at 58 psig.
- This pressure is normally maintained at 57 to 60 psig. The r NPO contacted the RCO and notified him that he would be bringing the pressure up to approximately 60 psig. When the i
hydrogen sup11y. header was aligned to the generator, control room - annunctator. "H2 Manf -Sply Press Hi/Lo" alarmed - as expscted due to low header pressure and remained illuminated. l The NPO left the area to continue his rounds. At~
.approximately 2:00 a.m., the control room requested the NPO r; come to the control room and assist in a digital electro hydraulic loss of load test. This test was completed at about
- 2:24 a.m. The NPO then completed his round and returned to '
i his office area.
; At about 3:20 a.m., the ANPS noticed that the "H2 Manf Sply .
Press Hi/Lo" annunciator was illuminated. The RCO checked the inydrogen pressure and found it to-be 80 psig. The RCO then directed the NPO to , secure the hydrogen and reduce the j generator gas pressure to 60 psig. l Licensee investigation of.this event determined that the NP0 ! and control room operators did not apply sufficient detail to
- the progress of this evolution. The NPO allowed himself to be assigned to another task and lost control'of the status of he
- evolution. The generator hydrogen filling evolution was not 4
adequately tracked by the RCO and ANPS. They also permitted ,
- the "H2 Manf Sply Press Hi/Lo" annunciator to stay illuminated for about two hours when the filling evolution should have i taken approximately 30 minutes. The licensee also found that a generator high gas pressure alarm should have sounded and s actuated an annunciator in the control room. The local alarms l were found to be inoperable with existing PW0s that required work.
$ This event clearly pointed out- a failure of the NPO and RC0 to maintain status while adding hyt ogen to the main generator
- and the failure to reset a control room alarm. It also showed that an operator must stay aware of the status of alarms on equipment and take compensatory actions if normal annur.ciators
- are not available. This item is identified as a weakness.
A subsequent inspection and evaluation by the equipment vendor i determined that the generator had not been damaged as a result of this event.
- c. Plant Housekeeping (71707)
! Storage of material and components, and cleanliness cor.Jitions of
- various areas throughout the facility were observed and no safety 7 and/or fire hazards were identified.
~
$ 26 4
9
- d. ~ Clearances (71707)
During this inspection period, the inspectors reviewed the following tagouts (clearancep):
*' l-95-009-011 on EDG 1B fuel oil transfer pump. The inspector found the clearance tag in place and the breaker in, the off position as required.
- 2-95-09-002 - control valve V-3661 for SIT outlet drain valve to RDT.. The inspector found the valve in the closed position with fuses removed from RTGB-206.
No deficiencies were identified.
- e. Technical Specification Compliance (71707) .
Licensee compliance with selected TS LCOs was verified. This included the review of selected surveillance test results. These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records. Instrumentation and recorder
- traces were observed for abnormalities. The licensee's compliance
. with LCO action statements was reviewed on selected occurrences as they- happened. The inspectors verified that i. lated plant procedures in use were adequate, complete, and included the most L
recent revisions. *
- f. Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems (40500)
- 1) Licensee Self Assessment i
The inspector reviewed a special QC assessment of decisions that led to the inadvertent spraydown of Unit I containment. This assessment was requested by the FPL Nuclear Division Vice President and focused on the plant's decision to operate Unit I with FCV 07-1A in the open position and the development and execution of new procedure CP 1-0420060, " Venting of Emergency ; Core Cooling and Containryt 4 pray System." This review found that operatin~g the C!i~ system in an abnormal lineup and executing a'new procedure under this condition, coupled with operator error resulted in spraydown of Unit I containment. The assessment also noted that schedule pressure may have prevented timely repair ' of the CS valve FCV 07-1A. The , . inspector noted that the assessment was detailed and provided some recommendations for improvement. l The inspector also noted that the assessment identified that 1 I the quarterly surveillance test directed that FCV 07-1A be ) lubricated immediately prior to the performan e of - its ; scheduledL surveillance. The inspector questioned this j 29 l l 1
practir.e since prelubricating the valve prior to performance of the surveillance test would not result in testing the valve's ability to provide the required response time during an actuation. The licensee agreed with this and changed the procedure to delete the prelubrication under TCN 2-95-177 on September 7, 1995. The inspector also questioned why QA had not documented this' deficiency under the STAR program as required by QI 16-PR/PSL-2, Rev 1. "St. Lucie Action Report (STAR) Program," Section 5.1, " Initiation of a - STAR Form." As a result of the question, a STAR was generated on September 6. The failure to document the subject finding via the STAR process is an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 7).
- g. Unit 1 Restart Activities The inspector accompanied maintenance QC on a walkdown of the Unit 1 containment prior to unit restart. This inspection by QC was conducted after departmental heads had completed their final inspection, as specified in AP 0010728. It was noted that these department tours had been completed and signed off (with a few
. . exceptions for items that would be as a part of unit restart). The inspector and QC identified approximately ' 40 deficiencies :that needed to be corrected prior to unit restart. These included:
- Burned out lights
- Missing covers on electrical outlets and componants
- Electrical box and panel covers that had not been tightsed
- Areas that needed additional cleaning
- Some small trash and debris on top of components A scaffold that had not been removed
- Missing screws and bolts in various components
- Missing condulet covers The inspector noted that the majority of the deficiencies were the responsibility of Electrical Maintenance. A meeting was held with
, the Maintenance Manager to discuss the items after the inspection was complete. He indicated that these items would be corrected prior to restart and that responsible managers would be counseled on j this item. The inspector found that the QC walkdown was very thorough. Discussions with QC found that QC had conducted several inspections prior to this final closeout inspection to verify that containment i was being prepared for closeout. IR 94-24 noted that at the c wpletion of the Unit I refueling outage in November 1994 the NRC als:, accompanied QC on the final closecut inspection and identified 1 similar conditions to that found in this inspection. That IR also !
- identified that heavy management reliance was placed on QC to verify i the readiness of containment closure. Although containment was ;
j 30 j 4 l
.----a-- m-- , -- n , w
i returned to a final satisfactory condition it appears that licensee
~
management is employing QC in a line. function rather than quality 4 verification role. This item is identified as a management weakness. t
- 4. . Maintenance and Surveillance
- a. Maintenance 0bservations (62703)
Station maintenance activities involving selected safety-related systems.and components were observ.ed/ rey'iewed to ascertain that they were conducted in accordance with requirements. The following items-were considered during this review: LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations were performed prior to returning components or systems , to service; quality control records were maintained; activities were , accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as , required. l fork re' quests were reviewed to determine the status of outstanding jobs and to ensure that priority was assigned to safety-related equipment. Portions of the following maintenance activities - were observed:
- 1) PWO 61/5570 and PWO 61/5571 - Remove PORY 1402 and 1404 from pressurizer, bench test, repair as necessary and reinstall.
The valves had been identified as inoperable and the above PW0s were generated to remove the valves, determine the cause of failure and correct. The valves were removed and worked using MP l-M-0037, Rev 6, " Power-Operated Relief Valve i Maintenance." The inspector observed selected portions of the valve , disassembly and troubleshooting to determine the cause of l failure. These efforts involved several shifts over several days. This work was accomplished in a contaminated work area , in Unit 2 RAB. The inspector noted that HP coverage was provided and that a vendor representative assisted maintenance in this effort. The inspector also noted that continuous supervisory oversight and engineering support were present in the field to provide for a timely repair of tnese components. These items were worked around the clock since they delayed plant restart. The inspector also noten, that calibrated tools were being used and that QC provided coverage of this job. The inspector found that work procedures and PWO were in the field and being used. - At the completion of the above work, the inspector reviewed the completed work package documentation and found that TC had been implemented for required procedure changes, repair. parts, and work- was correctly documented, and other support
- documentation was properly filled out.
31 l
< l
Overall, the personnel performing this task were adequately qualified and used the appropriate procedures. The overall work effort resulted in identifying, correcting the problem
< and returnin'g the PORVs to service. Adequate supervisory, ; engineering, and vendor support was provided to successfully
- complete the- task in a timely manner. See IR 95-16 for a
- detailed description of the root cause of the noted PORY ,
i inoperability. j 2) PWO 1230/65 Perfonn PCM 11-195 on DG 1A/IB. The inspector, while conducting routine. plant inspections, observed that work on this modification was in progress on DG , IB. Two electricians were completing the work activities ~ i associated with installing new splice boxes for the trip solenoids on the 12 and 16 cylinder engines for DG 18. The , inspector reviewed the PWO and procedure that the technicians [ were using. He noted that the work was nearly complete on the
- 12 cylinder engine, but only the first few steps of the procedure had been signed off. He questioned the electrician as to what work had been completed and the electrician stated i that he had terminated the wiring, torqued the connections, i
and applied several layers of different types of tape in the sequence indicated by the PC/M. Noting that only a few steps of the PC/M had been signed off, the inspector asked specific questions as to the wiring identification, torquing requirements, and sequence and type of tapes used. l The electrician was unable to locate the guidance provided for
- wiring identification for correct termination and admitted j that, although he had torqued the connection to the correct value, he did not document this in the work package when the step was accomplished. He also stated that he had taken over ,
- this job from another individual arid had only scanned through '
- the work package instructions and details. Further review of his work activity and the work package by the inspector ,
- determined that the connections had been correctly made and i i the correct torque value had been used.
The circuitry was tested on the night of August 31 and performed satisfactorily. The inspector discussed this item ] in detail with the Maintenance Manager and noted that not filling out procedural steps as they are accomplished, doing l only a cursor knowledgeable' y review of all aspectsofofa the work jobpackage, can leadand not being to serious errors or mistakes in the performance of maintenance activities. The Maintenance Manager stated that he agreed with the inspector's observations and that corrective action would be taken in this concern. I ADM-08.02, Rev 7, " Conduct of Maintenance," Appendix 5, Step 5, required that procedures be present during work and that . 32 4 1
I individual steps be initialed once performed. . The noted failure of the electrician to initial procedural steps on an as-completed basis is an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 8).
. 3) PWO 95-02-4066 Remove Cylinder Head No. 9, Inspect for Damage.
This PWO was later expanded to perform repairs. The inspector conducted periodic inspections of these activities as they occurred over a period of approximately one week. Additional details and evaluation of this work is contained in paragraph 3.'b.11) .
. a. .
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EICS ENFORCEMENT WORKSHEET EICS MEETING NOTES AND DOCUMENTATION OF UNDERSTANDING a j'h $SU EA NLM ER: k 383 ATTDEEES FACILITY: .Jf M J7ed J'M owl M SbuECT: d%MAv/ a[//fda#ce- [ad A4#d AEL a PEC a CAUCUS 4)dnt.- o OTER a 01 BRIEF /4 J INSPECTION EM) DATE: 9!#o!</4, (* VIA TEEPHONE) PREPARED BY: .-} 6' F M ' DATE: /c/7,/$ TIE: /0 ff/x
/ / /
I. EICS STAFF NOTES: N8'4 / clusuk/ Zbe utt$Ces m s2%AJ . u-m efdw A ' una u psvr Aae& w t ne ass - s O d A f> E r am, Ana ddr} MAS M a @ ud JA &m'hk ~ ~>uM> ~ nL,d~'f a do h dikr 100 Z } us 4 awA </'sa au ~_hA l LL L w 'n m nw 's h-~ _ %& \ N " ao mA 4 l4 Y n-mzus e .m Aa Adk' Ad A. JAv 'A .Jr J L <N6'.-l4-r, a}m 1 cn& a- a ve' i f A z 'u Mr . deas a '--BL w md 6Gih 96-00 M-4 / - L 6 lad 6 : Ris u & ser1x d' 5 uiL turf P' d'L 7Y nd 7 no uitp d J ANtri/7.s8 ~- : n wAa.bem- n a ose> nt& A l
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i i l f 2 ENFORCEENT ACTION WORKSHEET EICS EETING N(HES AND DOCUENTATION OF Ul0ERSTAM)ING 4 II. Civil Penalty Assessment A. First non willful SL III violation in 2 vears/2 inspections? YES or NO Previous escalated cases: B. Identification Credit? YES - NO - N/A
- RC identified?
Licensee identified? I Revealed through an event?* Prior opportunities? C. Corrective action credit? YES - NO - N/A Inmediate corrective actions: 1 1 Long term corrective actions to prevent recurrence: ] D. Discretion anolied? Yes or No: Reason why. 1 E. Civil Penalty: F. Recommendation for predecisional enforc; .it co6ference: d
.(
4 .
e 3 ENFORCEMENT ACTION WORKSHEET EICS EETING NOTES M DOCUENfATION OF (20ERSTEING NOTE: Complete the following infomtion for each violation ISSLE: III. Documentation of Enforcement Panel / Caucus Consensus A. Preliminary Severity Level (Prior to Application of ary Discretion. Free Part I) B. Increase Severity Level based on Aggregation? C. Increase Severity Level for Repeat Violations? (Address rexpirements of ROI 0903) D. Increase Severity Level for Willfulness? E. SEVERITY LEVEL SUPPL M.KT/SECTION F. Recommended Civil Penalty G. Predecisional Enforcement Conference Necessary? H. Revision to Draft NOV Required? I. Formal Review by OE Required? - J. Special Action Items / Nessage to Licensee / Comments f
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e 1 j ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE INFORMATION REOUIRED TO dE AVAILABLE PRIOR TO ENFORCEMENT PANEL 1 PREPARED BY: Kleinsorce/Blake DATE PREPARED: Aoril 7, 1993 NOTE: The Section Chief is responsible for preparation.of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This information will be used by EICS to , prepare the enforcement letter and Notice, as well as the transmittal memo to the Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St Lucie Unit (s) : Unit 2 Docket Nos: 50-389 License Nos: NPF-16 Inspection Dates: March 10-17, 1993 Lead Inspector W. P. Kleinsorne ;
1
- 2. NOTES:
A. A draft Notice of Violation, including the recommended severity level for each violation, should be enclosed. , The . violation (s) in the Notice should be carefully !
- considered by both the inspector and Section Chief, and j should be comolete regarding the specific requirement to i be cited and the appropriate level of specificity as to how and when the requirement was violated.
B. Copies of applicable Technical Specifications or license conditions cited in the Notice should be enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) ,
that best fits the violation (s)- (e.g. , Supplement I.C.2) j I.C.6. A licensee f ailure to conduct adecuate oversicht of l l vendors resultino in the use of uroducts or services that are l .g of defective or indeterminate cuality and that have safety 1 sianificance. ) 1 l
. , k A > 4. What is the apparent root cause of the violation or problem?
The failure of the licensee and the vendor (NSSS) to comoare crocedure recuirements with the ASME Code L. State the message that should be g.icen to the licensee (and industry) through this enforcement action. Licensee's are responsible for the assurance that vendor activities are conducted in comoliance with covernina codes and standards.
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.): ;
- a. IDENTIFICATIOE: (Who identified the violation? What were the facts and e.ircumstances related to the discovery of the violation? Was it self-disclosing? Was it identified as a result of a generic notification?)
__Ibg violation was identified by a recion-based NRC insoector while comoarina crocedure and ASME Code __r_gguirements after observina weldina activities in the field.
- b. CORRECTIVE ACTIDH: Although we eqe :t to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
The improcerly deoosited veld material was removed by cripdina, crocedures rewritten, and welds _oronerly comoleted in accordance with the ASME Code reauirements What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? Immediate work stoonaae until immmediate corrective _ actions were comoleted. Problem reoort initated. ,, l
y , .1 i
,- I ja ..
. .What was the degree of licensee initiative to address the violation and.the' adequacy of root.cause analysia?
The violation was discovered on a Saturday afternoon. A sianificdnt~ number of ' licensee eersonnel worked throuah the weekend to detarmine the scone and cause of the oroblem (s) and to start recoverv.
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two !
inspections, whichever is longer. 1 List,past. violations that may be related to the current 3 violation (include specific requirement cited and the 1 date issued): 1
- i
, None identified '
. Identify the applicaole SALP category, the
- rating for this category and ' the overall
. rating for the last two SALP periods, as well 4 as any trend indicated: 1 l
5 Salo Period Ena/TS Maint/Surv Nov 1, 1990 - May 2. 1992 1 1 May 1. 1989 - Oct 31, 1990 1 2 7
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities
- for the licensee to discover the violation sooner such as through normal ' surveillances, audits, QA activities, j specific NRC or industry notification, or reports by employeea?
i i The weldina crocedures went throuch multiole reviews by ) s 4 vendor and licensee technical staffs. l 4 i e i
s
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this inspection? If there were, identify the number of examples and briefly describe each one.
The NOV lists three examoles of instances where ASME code recuirements were not orocerly included in the work crocedures. The first example is the imoroner weld electrode size for the temoerina bead weld operation. The second examole is the imnrocer location o f. thermocouoles recuired to monitor the oreheat and internass temoeratures . The third example is the removal of temocrary attachments without markina their location for subsecuent NDE examination.
- f. DURATION: How long did the violation exist?
l Weldina coerations occurred March 12. 1993, violation identified by NRC on March 13, 1993. ADDITIONAL COMMENTS / NOTES: The vendor. ABB/CE conducted weld 1 i cualification testina to determine the effect of usina the e wrono size electrod on the temoerina bead weld. The results of the testina were completed on April 1 1993, and concluded that the 3/32" diameter electrode temoerina bead lef t the heat affected base material in an accropriate temoered condition. l The ABB/CE report will be included as a cart of the licensee's problem report.
li I ENCLOSURE 1 NOTICE OF VIOLATION Florida Power and Light Docket Nos.: 50-389 St.'Lucie License No.: NPF-16 During an NRC inspection conducted on March 10-17, 1993, a l violation of NRC requirements was identified. In accordance with :) the " General Statement of Policy and Procedure for NRC Enforcement o Actions," 10 CFR Part 2, Appendix C, the violation is listed below: A. 10 CFR, Part 50, Appendix B, Criterion IX, as implemented by FPL Topical Quality Assurance Report (FPLTOOAR 1-76A), requires that measures be established to assure that special processes, including welding, be accomplished in accordance with applicable codes. The Amerit:an Society of Mechanical Engineers Boiler and Pressure Vessel (ASME B&PV) Code, Section III,'1986 Edition with no Addenda, Subsection NB, has been identified as the applicable code for the repair of the St. Lucie Unit 2 Pressurizer. Specific requirements are as follows: [1] ASME B&PV Code Section III, Paragraph NB-4 6 22.11 (c) (6 ) , requires that the first layer of weld metal of a temper bead repair be deposited using a 3/32 inch diameter electrodes, that the weld bead crown be removed by grinding, and the second. layer be deposited i with an 1/8 inch diameter electrode. ; i [2] Paragraph NB-4622.11(c) (5) , requires that the weld I j area, on a temper bead repair, plus a band around the weld for five inches be preheated to a minimum l temperature of 350 *F and a maximum interpass temperature of 450 *F during welding, monitored by thermocouples and recording instruments. [3] Paragraphs NB-4622.11(c) (5) and NB-4435(b) require the immediate area around the temporarily attached thermocouples be marked so the removal area can be j identified after their removal for subsequent j Nondestructive Examination, j Contrary to the above, on March 13, 1993, effective measures ; had not been established to assure that special process of l welding was accomplished in accordance with applicable codes ) as evidenced by the following. l 1 The requirements of ASME B&PV Code Paragraphs Nos. [1] a NB-4 622.11 (c) (6) , [2] NB-4622.11 (c) (5) , [3] NB- l 4 622.11 (c) (5) , and NB-4435 (b) were not incorporated or not ! correctly incorporated into the instructions and procedures ! - for the accomplishment of the temper bead repair to four l Pressurizer one inch vapor space nozzles. These discrepancies , l l I
. . q.
.4 i
- went-undetected'by_the authors and all the reviewers at the Nuclear- . Steam Supply System -supplier,- ' ASEA Brown
'Boveri/ Combustion Engineering, as.well as.all the licensee's reviewers, . including the St. Lucie Facility Review Group. The l end result of'.above discrepancies and oversights was ' the following:
.On March 13, 1993, the following'. violations.were identified: i
[1] the second layer of the temper bead repair to all
-four Pressurizer one inch vapor space nozzles was deposited with 3/3?. inch diameter electrodes,
,[2] the preheat temperature of a band of only four inches or-less, in lieu of.the five inches required, around the welds was monitored, and.
[3] the temporary attachment thermocouple welds were not marked prior'to their removal.
, r, This is a Severity Level IV violation (Supplement I).
D t s 1 4 5
.- b f
8 m... ._m
=
1 o ENFORCEMENT ACTION WORKSHEET Failure to Maintain Overtime Within Guidelines PREPARED BY: Mark S. Hiller DATE: 7/3/96 NOTE: The Section Chief of the responsible Division is responsible for preparation of_ this EAW and its distribution to attendees prior to an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e-mail [ENF.GRP. CFE. OEMAIL. JXL. JRG. SHL. LTD: appropriate RII DRP. DRS: appropriate NRR. NMS?). A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is required. Capies of applicable Technical Specifications or license conditions cited in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed. a This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of. specificity as to how and _ when the requirement was violated. Signature Facility: St. Lucie Unit (s): 1&2 Docket Nos: 50 335, 50 389 License Nos: DPR 67. NPF 16 Inspection Report No: 96 09 Inspection Dates: June 9 - July 6,1996 l Lead Inspector: Mark Miller l
- 1. Brief Summary of Inspection Findings: A review of overtime over a one i month period indicated that 56 individual deviations from TS required {
overtime guidelines occurred. The deviations were not approved by plant management, as required by TS. The deviations were committed by 5 individuals. The number of examples of the proposed violation indicates ! particularly poor performance by the licensee in this area. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
-r
- 2. Analysis of Root Caus!: Failure on the part of the individuals involved, to recognize the need for approved deviation requests, i
failures, on the part of plant management, to conduct effective reviews 1 of overtime usage, , With regard to the differences between gate logs and timesheets, comments were also received indicating that, while management had stated 1 that overtime guidelines should not be exceeded, an unexpressed pressure : was perceived to meet outage schedules which led to work performed "off the clock." Additional comments were received which indicated that all of the parties interviewed were motivated by a desire to see jobs through to completion, with several stating that their own expectations for their performance factored into decisions to work extra hours.
- 3. Basis for Severity Level (Safety Significance): No operational event or
. challenge to a safety system has been identified as a result of the violation identified. This is proposed as a SL IV violation, Supplement I, D.3, a failure to meet regulatory requirements that have more than minor safety significance.
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
EA 96-249 10 CFR 50.59 Deficiencies. Supplement 1. 7/96. (pending) EA 96-236 Configuration Management Programmatic Breakdown. Supplement 1, 7/96 (pending) EA 96-040 Boron Overdilution Event. Supplement 1, 1/22/96 EA 95-180 Inoperable PORVs due to inadequate PMT. Supplement 1. 8/4/95
- 5. Identification Credit? No Consider following and discuss if applicable below:
a Licensee-identified a Revealed through event a NRC-ioentified a Mixed identification a Missed opportunities Enter date Licensee was aware of issues requiring corrective actions: 6/6/96 Explain application of identified credit, who and how identified and consideration of missed opportunities: The issue of excessive overtime was identified by the licensee's OA organization in an audit conducted for the period of May 9 through 18. The NRC identified the issue in an audit conducted for the period of May 13 through June 13. The NRC was unaware of the licensee's audit. On June 6. 0A discussed the issue with the Plant General Manager (PGM). Consequently, the Site VP at,d the PGM stressed personal accountability to their staff at morning meetings. Notwithstanding the licensee's immediate corrective actions, the NRC inspection identified 23 examples of unapproved deviations from the overtime guidelines in the time period from June 7 through 13. While the licensee's 0A organization was able to identify cases of excessive overtime, the licensee's program for controlling overtime usage was ineffective in identifying the issue sooner. By procedure, the licensee's management was to perform monthly reviews of overtime PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE
.WITHOUT THE APPROVAL OF THE DIRECTOR, OE j
i usage. ' The' procedure failed to s)ecify which managers were responsible
, for the required reviews or how t1e reviews were to be conducted.
Consequently, opportunities to identify the problem were missed.
- 6. Corrective Action Credit? Yes Brief summary of corrective actions:
e Site VP and PGM discussed the problem with their staff at-morning meetings stressing expectations for personal accountability in this area, e PGM issued letter to department heads on June 19 restating gujdelines and restressing personal accountability and the possibility for discipline for violation of the policy. e The Site Services Manager proposed a monthly spot check of high overtime users, comparing time sheet totals to gate logs. e The site VP explained to site management at a morning meeting, and later reiterated to the SRI. that it is his expectation that personnel working beyond guidelines receive prior approval, receive direct management oversight to ensure that fatigue does not impede the employee's abilities to work safely, and that , employees wo'rking excessive hours receive a ride home and that someone else drive the employee's car home. a OA has subsequently performed an audit of overtime use in the I&C department (the group showing the most examples of the inspector's i violation) and has found no deficienciec indicating that corrective action has been effective in C.e short term. Explain application of corrective action credit: The licensee's actions to date appear to have reestablished control over overtime usage.
- 7. Candidate For Discretion? [See attached list] [ Enter Yes or No]:
1 Explain basis for discretion consideration:
- 8. Is A Predecisional Enforcement Conference Necessary? No Why:
Severity of violation does not warrant conference. Additionally, no new information is predicted to be obtained. If yes, should OE or OGC attend? [ Enter Yes er No]: Should conference be closed?- [ Enter Yes or No]:
- 9. Non Routine Issues / Additional Information:
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
. /
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: [EICS to provide] [If inconsistent include:] ,
Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Message:
A strong commitment to maintaining overtime usage at acceptable levels is necessary to minimize the potential for-human error which might result in challenges to safety.
- 12. Recommended Enforcement Action:
~
SL IV
- 13. This Case Meets the Criteria for a Delegated Case. LEICS - Enter Yes or No]
- 14. Should This Action Be Sent to OE For Full Review? [EICS - Enter Yes or No]
If yes why:
- 15. Regional Counsel Review [EICS to obtain]
No Legal Objection Dated:
- 16. Exempt from Timeliness: [EICS)
Basis for Exemption: Enforcement Coordinator: DATE: l' e 8 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
ENFORCEMENT ACTION WORKSHEET ISSUES TO CONSIDER FOR DISCRETION a Problems categorized at Severity Level I or II. a Case involves overexposure or release of radiolog'ical material in excess of NRC requirements. a , Case involves particularly poor licensee performance. a Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with 01 regarding the case, whether or not the matter has been formally referred to 0I. and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included. a Current violation .is directly repetitive of an earlier violation, a Excessive duration of a problem resulted in a substantial increase in risk. a Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. a Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) a Licensee's sustained performance has been particularly good. - a Discretion should be exercised by escalating or mitigating to ensure that the proposed civil aenalty reflects the NRC's concern regarding the violation at issue and tlat it conveys the appropriate message to the licensee. Explain. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE MIITHOUT THE APPROVAL OF THE DIRECTOR, OE
f Enclosure 3 REFERENCE DOCUMENT CHECKLIST [x] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: IR 96 09 [x] Licensee reports: Quality Assurance Audit QSL PM 96 08 [x] Applicable Tech Specs along with bases: [] Applicable license conditions [x] Applicable licensee procedures or extracts AP 0010119 Rev. 14 e [x] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results Typical time sheet [] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [] Other miscellaneous documents (List): PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
N 08.X Control of Overtime The inspector revimd the licensee's control of overtime for the period of May 13 through me 13. The inspector obtained gate logs for 26 individuals. The selected individua' . were chosen from the licensee's maintenance, engineering, planning, and management organizations based upon their involvement in outage activities and the inspector's understanding of the activities under their cognizance. From the results obtained (which demonstrated time spent on site), the inspector reduced the inspection po)dlation to five individuals based upon indications of excessive lours. The individuals in question included supervisors and engineers with responsibilities for safety-related work. As acceptance criteria, the inspector reviewed TS 6.2.f. which required that the hours expended by personnel performing safety-related functions be limited, with an objective that personnel work a normal 8 hour day, 40 hour week while the plant was operating. The TS observed that substantial amounts of overtime might be required during extended periods of shutdown for refueling, and established guidelines for these periods. The TS stated"
...on a temporary basis the following guidelines shall be followed:
- a. An individual should not be permitted to work more than 16 hours straight, excluding shift turnover time,
- b. An individual should not be permitted to work more than 16 hours in any 24 hour period, nor more than 24 hours in any 48 hour period, nor more than 72 hours in any 7-day period, all excluding shift turnover time. ,
- c. A break of at least 8 hours should be allowed between work peri Js. including shift turnover time. . .
....Any deviations from the above guidelines shall be authorized by the Plant General Manager or his deputy, or higher levels of management, in accordance with established plant procedures and with documentation of the basis for the deviation." The inspector reviewed AP 0010119, revision 14. " Overtime Limitations for Plant Personnel," and found that the procedure appropriately implemented the TS requirements.
The inspector found that the licensee deviated from TS guidelines for the control of overtime without the prior (or subsequent) approval from senior plant management. Of the five individuals focused on as a result , of gate logs, the following information was obtained from timesheets l (violations of the recuirements were cited only for excesses of l requirements which hac not received approval per AP 0010119): l l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l l
i l l Individual- Violations of 72 Violations of Violations of 16 ' Hour Requirement 24/48 Hour Hour Requirement Requirement t A 3 0 0 B 0 0 0 C 5 1 0 D 14 2 0 3 E 16 12 3-Total 38 15 3 . The instances identified above, in which TS guidelines were exceeded, and for which the TS-required approvals for the deviations were not obtained, collectively represent a violation (VIO 96-09-XX. " Failure to Control Overtime"). While violations were identified, the inspector also noted that significant differences existed between timesheet records, which divided time between TS and non-TS categories, and gate records, which indicated total time on site. For the 5 individuals highlighted above, numerous instances of differences between total time on site and timesheet-indicated time on site existed, with differences frequently exceeding one and two hours and, at times, exceeding several hours. The most time spent continuously on site was noted to be approximately 26 hours. The inspector discussed the results above with the affected parties to ascertain the reasons for the excessive use of overtime and for the differences between gate logs and timesheets. Responses were mixed.
. Regarding the heavy use of overtime, several respondents pointed out that the project that they had been working was adversely affected by the loss of several key personnel (one to layoffs, one to death, and one to termination for cause), which reduced the depth of knowledge on the associated job.
Several stated that' the diverse activities on both units (due to the outage on Unit 1 and the recent trip of Unit 2) had placed increased demands on their time. In discussing the method for completing timesheets, the inspector found that a l lack of uniformity existed. Some respondents treated work periods (as described on the timesheet) as any work performed on a given calendar day. By applying this approach, the potential existed for the work hours recorded for a given day to represent a composite clue of two work periods if one (or cre) of the work periods extended across midnight. The Jotential result of this type of accounting was that the true length of a wort period, as. referenced in TS, would not be accurately reflected on timesheets, confounding I the ability to maintain an accurate count of daily, 48 hour and 7-day totals. With regard to not obtaining the appropriate deviation approvals for time worked in excess of the guidelines, several workers stated that they believed that obtaining a deviation provided a blanket authorization for overtime spent on the project for which the deviation applied. The inspector noted that the AP was not specific as to whether a deviation request was required for each PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
-f planned deviation from the guidelines or whethar it applied to the job which
~, was described on the request. The inspector discussed this issue with the Plant General Manager, who stated that it was his expectation that a deviation request be filed for each )lanned deviation of the guidelines (the implication being that a series of worc periods for which each period led to violations of one or more guidelines should each be documented on separate requests). The inspector had requested any deviation requests associated with the personnel audited for the subject time period. Two were identified which addressed themselves to 3 of the personnel. The deviations covered by these deviation requests were not considered in the summary table above.
AP 0010119 required that department heads perform a monthly review of assigned overtime to assure that excessive overtime was not assigned. The inspector questioned the licensee as to how those reviews were executed..... Independent of this inspection (and unknown by the inspector), the licensee's 0A organization performed an audit of overtime usage for the period from May 5 through 18. A population of 100 plant personnel was selected at random for the audit. 0A reviewed gate logs for the sam)le 30pulation and applied criteria which assumed a one half hour lunch areac and accepted turnover Seriods to reach the following criteria for determining whether guidelines hari Jeen exceeded: o No more than 17.5 hours in 1 day. e No more than 27 hours in a 48 hour period e No more than 82.5 hours in a 7 day period e An 8 hour break between work periods. 0A determined that 13% of their population exceeded the ci iteria at least once and that 8% exceeded the criteria at least twice. 0A infcrmed management of their findings in this area on June 6. As a result, the Site Vice President and the PGM discussed the problem with plant staff at morning meetings to stress expectations for personal accountability in this area. On June 19, the PGM issued a letter to department heads restating the overtime guidelines and stressing personal accountability on the issue. The inspector noted that, with respect to immediate corrective actions, 23 examples of unapproved deviations existed in the inspector's sample from June 8 through 13. As a result of this inspection, the inspector concluded the following: o Overtime usage for the period May 13 through June 13 has exceeded TS guidelines for a number of personnel. e The licensee failed to effectively control overtime as required in AP 0010119, revision 14. " Overtime Limitations for Plant Personnel " in that deviation requests were neither prepared nor approved for the majority of deviations identified. e AP 0010119 was unclear in its expectations, both for when a deviation request was required cnd for who was responsible for reviews of overtime usage (and how it was to be executed). PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
I
~
- o. The requirement for. monthly reviews of overtime usage, detailed in AP. I 0010119, was-ineffectively implemented. < ,
- e. ; Personnel have, at times, worked hours which were not recorded on timesheets. !
I i l
)
f' PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE , WITHOUT THE APPROVAL OF THE DIRECTOR, OE i
- I
.j l PREDECISIONAL :
, DRAFT INFORMATION - NOT FOR DISTRIBl1 TION NOTICE OF VIOLATION Florida Power & Light Company Docket Nos. 50-335 and 50-389 St. Lucie 1 and 2 License Nos. DPR-67 and NPF-16 During an NRC inspection conducted on June 9 through July 6,1996, violations of NRC requirements were identified. In accordance with the " General ;
- Statement of Policy and Procedure for NRC Enforcement Actions," (60 FR 34381
June 30, 1995), the violations are listed below. , i A. iechnical Specification 6.2,f, requires that the hours expended by k personnel performing safety-related functions be limited and that during extended periods of shutdown for refueling, the following guidelines be - i observed: ;
- 3. An individual should not be permitted to work more than 16 hours
- straight, excluding shift turnover time. ;
- b. An individual should not be permitted to work more than 16 hours in any 24 hour period, nor more than 24 hours in any 48 hour
- period, nor more than 72 hours in any 7-day period, all excluding
- shift turnover time, i i The Specification further reauired that any deviations from the above ;
guidelines be authorized by the Plant General Manager or his deputy, or
,. higher levels of management, in accordance with established plant i procedures and with documentation of the basis for the deviation. AP 0010119, revision 14 " Overtime Limitations for Plant Personnel,"
implemented this requirement and 3rovided an administrative vehicle for the approval of deviations from tie specified guidelines. Contrary to the above, during the period from May 13 through June 14, 1996, five individuals who performed safety related functions were found to have contributed to 38 deviations from the 72-hour-in-any-seven-day-period requirement,15 deviations from the 24-hour-in-any-48-hour requirement, and 3 deviations from the 16-hour-in-any-24-hour-requirement without obtaining authorization from the Plant General Manager, his deputy, or higher levels of management. l C:\WP51\DOClMNT\STLL\RPT5dLA WP Report printed 3.44 pn. Tuesday, January 14,1997 11
. l
1 4 5 ) l l ENFORCEMENT ACTION WORKSHEET l ST.'LUCIEUNIT1CONTAINMENTPIGINOPERABILITY-PREPARED BY: Mark S. Miller DATE: April 8,1996' NOTE: The Section Chief of the responsible Division is responsible for preparation of this EAW l t and its distribution to attendees prior to an Enforcement Panel. The section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e- '
- mail [ENF.GRP. CFE. OEMAll. JXL. JRG, SHL. LFD: appropriate Ril DRP. DRS: appropriate NRR, NHSS).
A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is required. Copies of applicable Technical Specifications or license conditions i
~
cited in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed. ] This Notice has been reviewed by the Branch Chief or Division Director and i - each violation includes the appropriate level of specificity as to how and ! when the requirement was violated. j F t Signature Facility: St. Lucie l Unit (s): -1 i Docket Nos: 50 335 , License Nos: DPR 67 Inspection Report No: 96 04 Inspection Dates: -2/18 3/20/ % Lead Inspector: M. Miller !
- 1. Brief Summary of Inspection Findings: Failure on the part of a health i Physics technician to follow a procedure resulted in ino)erability of a containment Particulate-Iodine-Gaseous (PIG) monitor. T1e technician 1 failed to open a valve which was closed to obtain a containment air sample. The closed valve resulted in severely restricting the flowaath ;
from the containment atmosphere to the containment PIG. rendering t1e instrument inoperable. Several non-licensed operators logging data failed to identify the problem over a three day period. Resultant inoperability resulted in licensee performing a reactor st6rtup without satisfying the TS LCO for RCS leakage detection, in that the PIG was required to satisfy the RCS leakage LCO. i
- 2. Analysis of Root Cause:
Failure to follow procedure, followed by inadequate log reviews and lack of a questioning attitude on the part of NL0s. ,
- 3. - Basis for Severity Level (Safety Significance): Supplement I. D1. The safety significance of the issue is-low. The monitor in question serves to provide indications of containment environment for identification of RCS leakage. It is backed up by separate containment radiation i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR, OE f
J
a maonitors, containment pressure instrumentation, and containment temperature indications. However, this example includes the failures of i I a number of personnel to perform as required and indicates that the ! licensee has not been successful in stemming the tide of personnel j attention-to-detail and procedural compliance issues. There should be a j strong cover letter comment! l, 4, Identify Previous Escalated Action Within 2 Years or 2 Inspections? l [by EA#. Supplement, and Identification date.) j e EA 95-180, Supplement I, 8/9/95 - Inoperable PORVs due to < maintenance and testing problems (SL III, $50,000 CP) , o EA 96-040. Sup)lement I,1/22/96 - Overdilution due to operator < inattention (S. III, $50,000 CP) Issued on 3/28/96: licensee response not received yet.
- 5. Identification Credit? Yes Consider following and discuss if applicable below:
X Licensee-identified a Revealed through event a NRC-identified a Mixed identification X Missed opportunities Enter date Licensee was aware of issues requiring corrective action: [2/24/96) Explain application of identified credit, who and how identified and consideration of missed opportunities: Condition was identified by licensee when a chemistry technician noticed low flow through the PIG while passing by the component. However, non-licensed operators logged the unacceptably low flow value on six occasions with an electronic data logger which required the NL0s to enter the data twice each time (because the data was out-of-spec). Corrective Action Credit? Yes 6. Brief summary of corrective actions: e Monitor returned to service e HP technician counseled / disciplined e Oas enhanced log reviews e H) revised air sampling procedure to include independent verification of valve positions following sampling e HP reviewed event with all technicians e setpoint for low flow switch under evaluation (switch was set to alarm at zero flow, but valve position allowed small amount of flow which, while inop'g PIG did not bring in alarm) Explain application of corrective action credit: Corrective action were appropriate to this circumstance in the short term: however, the licensee s treatment of the extent of condition may not be comprehensive enough. To date, the licensee has not identified those components o)erated by departments other than Operations whose ' operability could 3e affected during normal sampling. Corrective actions for previous events involving operations
- logging 3ractices and overall site procedural compliance should have prevented t11s event. >
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i
7._ ' Candidate For Discretion? [See. attached list] [Yes):
- Explain basis for. discretion' consideration
Potential candidate for escalation over the apparently low safety. significance, as it involves particularly poor. licensee performance . involved a number.of operator failurcs, and involves issues 'of attention
, ,to' detail and procedural compliance which have been a repetitive theme in the last 8 months. ,
,. 8. 'Is'A Predecisional Enforcement Conference Necessary? .
No-l .Why: However, the violations should be cited to' determine what the licensee
- . will do, as regards operator attention-to-detail, in response to this event, which is different from other. corrective actions taken in the-last 8 months.
. lIf yes, should OE or 0GC attend? Should conference be closed? l
- 9. Non Routine Issues / Additional Information:
, 10. This Action is Consistent With the Following Action (or Enforcement Guidance)' Previously Issued: Supplement I.D.1
- 11. Regulatory Message:
Operator attention to detail, a questioning attitude and a commitment
~to the highest standards of performance are paramount in providing a barrier to individual failures.
- 12. Recommended Enforcement Action:
SL IV with a strong cover letter coment. Not a candidate for NCV due
.to the number of previous enforcement actions (and subsequent corrective actions) based upon failures to follow procedures issued in the last two years.
- 13. This Case Meets the Criteria for a Delegated Case. No
- 14. Should This Action Be Sent to OE For Full Review? To be determined.
If yes why:
- 15. -Regional Counsel Review To be obtained at the panel No Legal Objection Dated:
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE 7 WITHOUT THE APPROVAL OF THE DIRECTOR, OE
- n. -. .. . .. . . ...- - . . - . - . - - - - - . - .
r*
- 16. Exempt from Timelines: No ,
Basis'for Exemption: j Enforcement Coordinator: *
. DATE:.
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J A 1 I l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR, OE '
?
I i. ENFORCEMENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION o a ' Problems categorized atl Severity Level I or II., i a Case involves overexposure or release of radiological material in excess ofNRCrequirements. X . Case involves particularly poor licensee performance. a Case (may) involve willfulness. Informationshouldbeinclddedto address whether or not the region has had discussions with 01 regarding the case, whether or not the matter has been formally referred to 01, I and whether or not OI intends to initiate an investigation. A , description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or , management involvement should also.be included. o Current violation is directly repetitive of an earlier violation, a Excessive duration of a problem resulted in a substantial increase in risk. o Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. O. Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) o Licensee's sustained performance has been particularb :4ood. X Discretion should be exercised by escalating or mitigating to ensure that the proposed civil 3enalty reflects the NRC's concern regarding the v1olation at issue and tlat it conveys the appropriate message to the licensee. Potential candidate for escalation over the apparently low ! safety significance, as it involves particularly poor licensee l performance, involved a number of operator failures, and involves issues ; of attention to detail and procedural compliance which have been a i repetitive theme in the'last 8 months. l l l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Enclosure 3 REFERENCE DOCUMENT CHECKLIST s [X] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: 96-04 excerpt [X) -Licensee reports: 335/96-03 [X] Applicable Tech Specs along with bases: [- ] Applicable license conditions , [X] Applicable licensee procedures or extracts [] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results [] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability 1 [] Referenced ORDERS or Confirmation of Action Letters
, [] Current SALP report summary and applicable report sections
[] Other miscellaneous documents (List): i l l l l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
3 04.2 Unit 1 Containment PIG Rendered 005 Due to Personnel Error , Following the Unit 1 trip of February 22 a number of containment entries were made to troubleshoot CEAs. -In preparation for one such
' entry, an HP technician was dispatched to obtain a grab sample of the containment atmosphere at 1:55 p.m. on February 22. The methodology for obtaining the sample involved attaching a removable air sampling device- '
to quick disconnect fittings which ) laced the device in a parallel path to the air flow moving through the 3IG unit. A valve (procedurally designated as valve 3) located between the quick connects was then to be throttled closed to force the air flow through the sample device at a predetermined rate. A sample was then to be taken for a minimum of 30 minutes, at which time the throttle valve was to be returned to its open position and the sample device was to be isolated at the quick disconnects and removed from the unit. When the HP technician performed the sample, he failed to return the throttle valve to its open position. The result was that flow through i > the PIG was reduced to ap3roximately 15% of the intended value, rendering the PIG inoperaale. The licensee's investigation of the event revealed that the HP technician failed to employ HPP-22, revision 2.
" Air Sampling." Step 7.5.1.R required that upon completion of the sampling, that valve 3 be returned to the full open position. In fact, the subject step was proceeded by a caution statement stating that valve 3 must be returned to the full open position. The failure of the HP technician to employ the governing procedure for obtaining air samples ,
is an apparent violation of 10 CFR 50 Appendix B. Criterion V; which l requires that activities affecting quality be performed in accordance i with documented procedures (VIO 96-04-XX, " Failure-to Employ Procedure i for Obtaining Containment Air Sample"). The PIG remained in its inoperable state until February 24, when a , chemistry technician performing an unrelated task noted the indicated l flow through the PIG at a value much lower than narmal (a fraction of one SCFM. vice 2.5 to 3.5 SCFM required by procedure) which resulted in the identification of the PIG's inoperability and its return to service. During that time. SNP0s recorded the lower-than normal flow values O during logtaking rounds once per shift.(small hand-held and when computers) a given parameter was to take logl sensed by the com) uter, the operator was prompted to enter the data again to verify tlat the out-of-specification value was, indeed, the intended value. In the case of PIG air flow. SNP0s logged the data twice each round without pursuing the cause for the low reading. AP 0010120. revision 79, " Conduct of Operations. Appendix F. " Log Keeping " stated, in part, " Log readings shall be compared to previous , readings to detect abnormal trends or conditions and verified to be ' within the minimum and maximum values for that parameter. All log readings outside the min / max values shall be circled with reasons stated for abnormal readings..." The failure of SNP0s to identify the low flow condition of the Unit I containment PIG and to provide reasons for the observed performance is an apparent violation (VIO 96-04-XX. Failure to Identify Adverse Trends During Log Reviews). Additionally, the ) PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE , WITHOUT THE APPROVAL OF THE DIRECTOR, OE
% i direction that out-of-specification values should be " circled" ir:dicated that the procedure was not current, as the direction was a clear ,
reference to paper logs (the predecessor of the data loggers), which had not been employed for some time by SNP0s. l TS 3.0.4 stated that " Entry into an OPEPATIONAL MODE or other specified applicability condition shall not be made when the conditions of the Limiting Condition for Operation are not met..." Unit 1 entered Mode 2 on 5:13 a.m. on February 24 with the containment PIG inoperable. TS. 3.4.6.1 requires the PIG to be operable in mode 2. This is an apparent violation (VIO 96-04-XX. " Failure to Satisfy a Technical Specification Limiting Condition for Operation Prior to a Mode Change"). The inspector reviewed the licensee's discussion of the event in LER 335 96-003-00. " Containment Particulate and Gaseous Monitor Out of Service Resulting in a Condition Prohibited by Technical S)ecifications Due to Personnel Error." In the LER, the licensee descri)ed corrective actions which included:
- Disciplining the HP technician involved in the event.
- Enhancement of both units' logs to include a written explanation for out-of-specification readings.
- Incorporating sign-offs in HP procedures for actions involving the manipulation of plant equipment.
e Reviewing the event with HP personnel emphasizing procedural compliance. The inspector reviewed revision 3 to HPP-22, and noted that the new revision included requirements that the control room be notified at the beginning and end of containment sampling (new requirements) and that independent verifications be made of valve positions following sampling. Similar changes were made to the procedure for Unit 2 sampling. The ins)ector discussed the event with the Operations Supervisor and asked w1 ether, in the past, the PIGS were declared ino)erable when sampling occurred and was informed that they had not, )ut that they would in the future. The inspector then requested a list of activities performed by organizations outside Operations, that could affect operability of TS components in ways similar to the subject event. The licensee identified. . . In summary, the inspector found that the undetected inoperability of the subject component was the result of not employing a procedure while performing a grab sample. The condition was extanded in time due to inadequate logtaking on the part of non-licensed operators and inadequate review of the logs taken. As a result of these failures, a violation of TS occurred when a reactor startup was performed with the component 00S. Additional weaknesses included a logging procedure which was not up-to-date and an historical failure on the part of Operations to declare the containment PIG 00$ when grab sampling was taking place. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
PROPOSED VIOLATIONS f Technical Specification 6.8.1.a requires that written procedures be established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33. Rev 2. February, 1978. Ap)endix A. paragra>h 1.d includes administrative procedures for procedural adlerence. OI 5-PR/PS_-1, Revision 68, " Preparation. Revision, Review /A) proval of , Procedures " Section 5.13.1, states that all procedures slall be strictly j adhered to. Contrary to the above: I
- a. Step 7.5.1.R of procedure HPP-22. Revision 2, " Air Sampling," required that valve 3 of the Unit 1 containment Particulate Iodine Gaseous ;
Monitor be returned to the open position following the 3erformance of a
> containment grab sample. On February 22, 1996, a healta physics technician performing a grab sample of the Unit 1 containment failed to return valve 3 to the open position and, as a result, rendered the monitor inoperable.
I
- b. AP 0010120, revision 79, " Conduct of Operations Appendix F. " Log ,
Keeping," recuired, in part, that " Log readings shall be compared to l previous reatings to detect abnormal trends or conditions and verified to be within the minimum and maximum values for that parameter. All log readings outside the min / max values shall be circled with reasons stated
; for abnormal readings (i.e., 00S, NPWO, ISOL, etc)." On February 22, 23, and 24 Senior Nuclear Plant Operators failed to perform adequate reviews of logs taken in the Unit 1 Reactor Auxiliary Building, as the out-of-specification log readings taken on the Unit 1 containment
- ~ particulate iodine gaseous monitor were not hilighted and explained. As a result, the Unit 1 containment Particulate Iodine Gaceous monitor
- remained inoperable and Unit 1 transitioned from Mode 3 to Mode 2 without satisfying Technical Specification Limiting Condition for . 1 Operation 3.4.6.1. The Mode transition was prohibited by Technical Specification 3.0.4. This is a Severity Level IV violation (Supplement I) i 0 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
a r a"44 - v
.I ENFORCEMENT ACTION WORKSHEET l
}
l INADEQUATE DESIGN CONTROL PREPARED BY: John W. York DATE: October 28, 1996 I NOTE: The ss : tion Chief of the responsible Division is responsible for preparation of this EAW ! and its distribution to attendees prior to an Enforcement Panel. The section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e-mail [ENF.GRP. CFE. OEMAIL. JXL. JRG. sHL. LFD: appropriate RII DRP. DRs; appropriate NRR. NHSs]. A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is required. Copies of applicable Technical specifications or license conditions cited in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed. This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. Signature Facility: St. Lucie Unit (s): 1 and 2 Docket Nos: 50 335, 389 License Nos: DPR 67. NPF 16 Inspection Report No: 96 17 Inspection Dates: 10/7-11, and 10/15 18, 1996 , Lead Inspector: John York
- 1. Brief Summary of Inspection Findings: [Always include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then, either sumarize the
. Inspection findings in this section or ref(rence and attach sections of the inspectico report. Inspectors are encouraged to utilize the Noncompliance Information Checklist provided in Enclosure 4 to ensure that the information gathered to support the violation is complete.] The licensee replaced some safety related nuclear instrumentation drawers during the Unit 1 Outage. The drawers were wired backwards because of incorrect drawings. Part of the root cause identified the lack of a proper independent verification as a potential cause. This is a violation of 10 CFR 50 Appendix B Criterion III In examining the safety aspects of this event, one additional example of inadequate design verification was identified for BEACON on line core performance monitoring system. In addition to the wiring problem for the drawers, the maintenance group connected the field cables for an NI backwards because the markings on the connectors were different than on the previous detectors. An NOV was written for failure to write a Condition Report (discrepancy report) and resolve this problem prior to installation of the detector. See attached IR feeder and proposed NOV for details. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
e suromemarr aerrou - l wommerr ; 2.. . Analysis of Root Cause: ; Lack of control .and procedural adherence in the licensee's program for ; preparing and implementing Plant Change / Modifications (PC/Ms).
- 3. Basis for Severity Level-(Safety Significance): -[ Include example from th'e
- supplementsi aggregation. repetitiveness, willfulness, etc.] *
. Aggregation of examples and application of Supplement I, C.7. a breakdown in the control of licensed activities involving two violations ;
that are related that collectively represent a potentially significant lack of attention.toward licensed activities. The safety significance of reversing the detector inputs to the NIS
' drawers substantially reduced the safety margin'between the TM/LP trip '
setpoint and the analysis limit even considering the increased TM/LP ' margin to the trip setpoint due to actual core operating conditions. r :
.'4
.. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
[by EA#, supplement, and Identification date.] > EA 96-249 - Inadequate 50.59 did not identify US0. 7/12/96 EA 96-040 Boron Overdilution Event. Supplement 1. 1/22/96 ' EA 95-180 - Inoperable PORVs due to Inadequate PMT. Supplement 1. 8/4/95 , 5' . Identification Credit? No i The miswired NI drawers were identified 4through an event (the failure' to , have the system respond properly). i. e. the analysis of the data by . Reactor Engineering discovered the miswiring of the NI drawers but the error in the drawing should have been discovered in the design control process. ; The design error associated with BEACON was identified through routine
-comparisons of actual lant data with predicted data. This error could have been discovered i the design control process.
Enter date Licensee was aware of issues requiring corrective action: 7/30/96
- 6. Corrective Action Credit? Yes Brief summary of corrective actions:
In response to th'e issue, the licensee adopted corrective actions which included- , e For immediate action the licensee prepared a change request for ; the modification package and channels A.C. and 0 were reconnected and testing was performed to verify proper NI response. e A root cause/self- assessment and training meeting for the .
. Engineering Department emphasizing importance of proper design 2
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE ; WITHOUT THE APPROVAL OF THE DIRECTOR. OE i A i
ENFORCEBENT ACTION womasazzr
'i .
verification and importance of questioning attitude. Tape was produced of this meeting for future engineering training. e Procedures (Engineering Quality Instructions) were revised to (1) ! require all critical aspects be verified during the PC/M. (2). emphasize that the same level of verification is required for < FC/Hs duplicated for the second unit, and (3) reinforce the verification requirements for safety related drawings. l e Walkdowns will be conducted (linear NIs) to revise any design documentation and tagging. o ASI targets will be established for future trending of ASI during power ascension. e Require cross-disciplinary reviews of design inputs , e Better documentation of assumptions in core design inputs and codes Explain application of corrective action credit: Corrective action appears to be of appropriate scope.
- 7. Candidate For Discretion? NO Explain basis for discretion consideration:
Since actual power conditions did not exceed trip setpoints, no escalation is warranted. Several examples of licensee's declining performance in engineering does not warrant mitigation. ! 8. Is A Predecisional Enforcement Conference Necessary? Yes 1 3 Why: l To determine adequacy of licensee's proposed long-term corrective actions regarding backward looks at modifications performed prior to the Unit 1 outage. This included discussions of other modifications that may not have been independently verified. If yes, should OE or OGC attend? [ Enter Yes or No): Should conference be closed? [ Enter Yes or No): l
- 9. Non Routine Issues / Additional Information: i i
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
0 ENFORCEMENT ACTION wommsnarr ,
- 10. This Action is Consistent With the Following Act! ion (or Enforcement .
Guidance) Previously Issued: [EICS to provide] [If inconsistent. include:] Basis for Inconsistency With Previously' Issued Actions (Guidance)
- 11. Regulatory Message:
Positive control must be established and maintained over the design process, with particular emphasis on properly performing independent design verification.
- 12. Recommended Enforcement Action:
SL III ,
- 13. This Case Meets the Criteria for a Delegated Case. [EICS - Enter Yes or No] ,
- 14. Should This Action Be Sent to OE For Full Review? [EICS - Enter Yes or No]
If yes why: I
- 15. Regional Counsel Review [EICStoobtain] '
No Legal Objection Dated-
- 16. Exempt from Timeliness: [EICS]
Basis for Exemption: ! I l Enforcement Coordinator: I DATE: l l l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l ENFORCEMENT ACTION WORKSHEET o ISSUES TO CONSIDER FOR DISCRETION l e o Problems categorized at Severity Level I or II.
~
o Case' involves overexposure or release of radiological material in excess I of NRC requirements. ! a Case involves particularly poor licensee performance. 1 o Case (may) involve willfulness. Information should be included to i address whether or not the region has had discussions with OI regarding the case, whether or not the matter has been formally referred to 01, and whether or not 31 intends to initiate an investigation. A . descriptjon, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included. , o Current violation is directly repetitive of an earlier violation. O Excessive duration of a problem resulted in a substantial increase in risk. j 1 o Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. O Cases-involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) ;
~
a Licensee's sustained performance has been particularly good. O Discretion should be exercised by escalating or mitigating to ensure that the proposed civil Senalty reflects the NRC's concern regarding the violation at issue and tlat it conveys the appropriate message to the licensee. Explain. l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE ; WITHOUT THE APPROVAL OF THE DIRECTOR, OE j
Enclosure 3-REFERENCE DOCUMENT CHECKLIST [ ]' NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: [] Licensee reports: > l l
'[ ] Applicable Tech Specs along with bases:
[] Applicable license conditions [] Applicable licensee procedures or extracts
-[ ] Copy of discrepant licensee documentation referred to in citations such as NRC. inspection record, or test results
[] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or Confirmation of Action Let[ers [] Current SALP report summary and ap'plicable report sections ) [] Other miscellaneous documents (List): 1 PROPOSED ENFOR' CEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l 4 C
hr NI INSPECTION ST...LUCIE-October 7-18, 1996 !
< ll . , On July 30, 1996, St. Lucie Unit I was operating at approximately 100 %
power when reactor engineering was analyzing the data taken during power t ascension and noted an anomaly in the results. The data indicated three
- of'the four excore linear detectors measured core power moving to the top of the core during power ascension. This was an unexpected -
'. )henomena and did not agree with the trend of the power moving to the ,
)ottom of the core indicated by RPS Channel B Linear Range Detector., ;
. Control Channel #9 Linear Range Detector, and the BEACON Core Power : Distribution Monitoring Sys. tem. Evaluation of the data collected '
- indicated that RPS Channels A.C and D could have reversed (rolled) leads ,
of the top and bottom chambers input to the RPS drawers. ! The modification performed during the outage associated with this problem was No. PC/M 009-195. During the outage, the licensee replaced the power range NI drawers for the Reactor Protection System (RPS) with new Gamma Metrics drawers. This modification combined the linear power ' range input to the RPS and the logarithmic wide range channel-into a j single drawer, i.e. reduced the number of drawers on Unit 1 from eight to four. This modification increased the limits of the instruments : range and replaced aging equipment. Engineering Verification-Root- Cause A design error was responsible for the reverse connection (rolled leads) on four NI safety related drawers on Unit 1. The Controlled Wiring e Diagram (CWD). no. JPN-009-195-001/002 depicted the upper Uncompensated
. Ion Chamber (UIC) connected to the lower JIC input at the NI drawer.
The root cause noted that the designer and the lead engineer interpreted conflicting information on the existing CWDs and made an assumption. The independent verification may have caught this error had the process been properly performed. The drawings were prepared by the lead designer with fnput from the lead engineer. The drawings were then checked by a second designer who had no special knowledge of the NI design. This check was essentially a drafting check. The drawings were then reviewed by the lead designer and then by the engineering supervisor. Engineering Quality Instructions (01) 1.7. Design Input / Verification, dated July 5,1995, states in part that " Design verification is the ,. process whereby a competent individual, who has remained independent of the design process, reviews the design inputs, ... and design output to verify design adequacy.. This independent review is provided to minimize the likelihood of design errors in items that are important to nuclear safety." Contrary to this requirement the first reviewer could not be considered as competent because he was not an engineer as required by b PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
c ; i 2 011.7 and the lead engineer as the third reviewer could not be considered to have remained independent.of this design project. - One of the action items to prevent recurrence was to check all the I&C -
.and electrical PC/M to see if all the drawing approval' signatures could qualify as independent verifiers. The licensee found three out of eight open modifications where this was a potential problem, two of these '
modifications were electrical and one was I&C.' This therefore is not an isolated case. This failure to perform independent verification , according to procedure is identified as exam)le'one of violation 50-335/96-17-XX. Failure to Control the Design )rocess According to the
. Requirements of 10 CFR 50. Appendix B. Criterion III.
" BEACON Core Power Distribution Monitoring System The licensee had installed BEACON during this refueling outage to replace the older IMPAX code used for in-core flux monitoring. ~ BEACON provided several significant improvements over IMPAX one being real-time flux profile monitoring. This improvement permitted reactor engineering , to identify the NIS problem quickly and initiate prompt corrective actions. , During power operations, reactor engineering used BEACON to obtain the actua in-core flux profile. The actual in-core flux profile was then used to verify compliance with Technical Specifications and provide l calibration information for the excore NIS drawers. As part of these routine surveillances, reactor engineering com) ares actual in-core flux
]rofile to the in-core flux profile predicted )y the core design code. ;
Reactor engineering noted larger than normal errors between actual and predicted in-core flux profile. Because BEACON used the same neutronics : engine as used in the core design code, reactor engineering could not explain the error and notified the corporate core design engineers. As part of the process to resolve these errors, it was discovered that a simplifying assumption, used to overcome limitations of the IMPAX, was not accounted for in the. original design of BEACON. This simplifying i assumption was used because the licensee had changed the fuel design to incorporate a longer end cap to prevent debris induced fuel failures. This longer end cap raised the overall core height by 2.64" causing an , offset between detector midplane and actual core midplane. The IMPAX 1 code assumed detector midplane was along core midplane and could nce I accommodate the 2.64" offset. Therefore. the licensee, after discussion ) with the fuel vendor (Siemans). used this simplifying assumption to essentially lower the core midplane by 2.64" so that final design output would be referenced to detector midplane: not core midplane. However, the engineer preparing the design input for BEACON was not aware of this simplifying assumption consequently BEACON was referenced to core midplane resulting in an increased error between the core design predicted in-core flux profile and actual in-core flux profile. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE ,
e 3 The licensee's root cause evaluation identified lack of cross-discipline review as the significant contributor to this design error. The inspector concurred with the licensee's evaluation. Engineering Quality Instructions (01) 1.7.. Design Input / Verification, dated July 5.1995, states in part that " Design verification is the process whereby a competent individual, who has remained independent of the design process, reviews the design inputs. .. and design output to verify design adequacy. This independent review is provided to' minimize the likelihood of design errors in items that are important to nuclear safety." Contrary to this requirement, the design inputs were not adequately reviewed by a competent individual in that the core midplane offset was not identified as a design input for BEACON. This failure to perform an adequate independent design review for the BEACON system is identified as example two of violation 50-335/96-17-XX Failure to Control the Design Process According to the Requirements of 10 CFR 50. Appendix B, Criterion III. The safety significance of reversing the detector inputs to the NIS drawers substantially reduced the safety margin between the TM/LP trip setpoint and the analysis limit even considering the increased TM/LP margin to the trip set)oint due to actual core operating conditions. The safety impact of t1e failure to identify the core and detector midplane offset on TM/LP or LPD safety limits was minimal. CONNECTOR SWAPS AT DETECTOR 6-CHANNEL B All four of the RPS Linear Range Detectors had the connectors reversed as previously discussed but the B channel unlike the other three 4 channels was giving the correct data. At the same time that the drawers I were being replaced on Unit 1, the detector for channel B (detector no. I
- 6) was being replaced as a maintenance activity. During connection of !
the field cables, the connections were reversed for the upper and lower detection chambers, thereby causing the B channel to record properly. The root cause for the swap of the cables was that the new detector had different labeling than the existing cables. The existing cables were labeled TOP SIG and B0T SIG, and the new detector had A and B. The . inspectors discussed this maintenance job with the I&C supervision who I had supervised the latter part of this maintenance project. Several opportunities were ) resented to the maintenance personnel, one when the detectors were checced out in the warehouse and a second time when this condition was noted in the field. Maintenance personnel should have resolved the labeling problem by writing a Condition Report (CR) and having a formal resolution. Administrative Procedure No. 0006130. Condition Reports, rev. 4, dated March 22. 1996. Par. 8.1.1.A states in part that "Any individual who becomes aware of a problem or discrepant condition should initiate a PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
4 CR. If doubt exists, a CR form should be initiated". 'This failure to ' comply with the requirements of the administrative procedure is identified as violation 50-335/96-17-YY. Failure to Initiate a Condition Report'for Labeling on Safety Related Detectors. i e i t l l l l I I l i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR, OE 1 l 1
4 o Violation 1 with two examples. 10 CFR 50 A]pendix B, " Quality Assurance Criteria for Nuclear Power Plants and r uel Reprocessing Plants," Criterion III requires, in aart, that ... design control measures shall provide for verifying or clecking the adequacy of design, such as the aerformance of design reviews...The verifying or checking process shall 3e 3erformed by individuals or groups other than those who performed t1e original design. but who may be from the same organization. FPL Topical Quality Assurance Report, TOR 3.0, revision 11. " Design Control," Section 3.2.4, " Design Verification " stated. in part, " Design control measures shall be established to independently verify design input... Design verification shall be performed by technically qualified individuals or groups other than those who performed the design. Engineering Quality Instructions 1.7 " Design Input / Verification " rev.1, dated July 5.1995, states in part. " Design verification is the process whereby a competent individual, who has remained independent of the design process, reviews the design inputs, ... and design output to verify design adequacy. Contrary to the above:
- 1. Contrary to the above, on July 30, 1996, it was discovered that a design change (PC/M 009-195) was completed without an independent design verification by a competent individual. Design change PC/M 009-195 to install new Gamma Metrics Nuclear. Instrumentation drawers was completed by a lead designer and a lead engineer.
This design change was independently verified by a second designer ; who had no special knowledge of the design. A engineering supervisor approved the design. Neither the second designer or l engineering supervisor had remained independent of the design l process.
- 2. Contrary to the above, on July 30, 1996, it was discovered that an I independent design review was not conducted for the installation ;
of a new core flux monitoring computer code BEACON. During ' initial operation of BEACON it was found that the code did not compensate for a core mid-plane ~ offset created by a previous core modification. The engineer who prepared the design was not cuare of the core mid-plane offset and the independent review of the new BEACON code did not identify this omission. Violation 2 Technical Specification 6.8. Procedures and Programs, paragraph 6.8.1 requires in part that written procedures recommended in Appendix A of Regulatory Guide 1.33 revision 2 February 1978. shall be established, implemented... PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE :
l s 2 Administrative Procedure No. 0006130, Condition Reports, revision 4. dated March 22, 1996.-Paragraph 8.1.1.A states in part:that."Any individual who becomes aware of a problem or discre) ant condition ... should initiate a CR. If doubt exists, a CR form s1ould be initiated". Contrary to the above, on July 30. 1996, Instrument and Control technicians installing a plant design change (PC/M 009-15) did not initiate a condition report when they became aware of a discrepant
. condition concernmg incorrectly marked cables. They continued to install the modification and an error was made that resulted in cross-wiring of the nuclear instrumentation system.
4 t P i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i
4 l j ENFORCEMENT ACTION WORKSHEET 1 1 INADEQUATE DESIGN CONTROL l PREPARED BY: John W. York DATE: October 28. 1996 i NOTE: The section Chief of the responsible Division is responsible for preparation of this EAW j and its distribution to attendees prior to an Enforcement Panel. The section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e-mail [ENF.GRP. CFE. OEMAIL. JXL. JRG. sHL. LFD: appropriate RII DRP. DRs; appropriate NRR. NHSs). A Notice of Violation (without "boilerplate7 which includes the recommended severity level for e the violation is required. Copies of applicable Technical specifications or license conditions cited in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed. This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. Signature j Facility: St. Lucie Unit (s): I and 2 Docket Nos: 50 335, 389 , License Nos: DPR 67, NPF-16 l Inspection Report No: 96 17 Inspection Dates: 10/7 11, and 10/15 18, 1996 Lead Inspector: John York
- 1. Brief Summary of Inspection Findings: [Always include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then either summarize the l inspection findings in this section or reference and attach sections of the inspection l report. Inspectors are encouraged to utilize the Noncompliance Information Checklist j provided in Enclosure 4 to ensure that the information gathered to support the violation 4 is complete.] .
I The licensee replaced some safety related nuclear instrumentation i drawers during the Unit 1 Outage. The drawers were wired backwards because of incorrect drawings. Part of the root cause identified the lack of a proper independent verification as a potential cause. This is a violation of 10 CFR 50 Appendix B Criterion III In examining the j safety aspects of this event, one additional examble of inadequate ; design verification was identified for BEACON on line core performance monitoring system. In addition to the wiring problem for the drawers the maintenance group connected the field cables for an NI backwards because the markings on j the connectors were different than on the previous detectors. An NOV was written for failure to write a Condition Report (discrepancy report) and resolve this problem prior to installation of the detector. See attached IR feeder and proposed NOV for details. l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE I WITHOUT THE APPROVAL OF THE DIRECTOR, OE
]
' \
ENFORCEMENT ACTION WORKSEEET
- 2. Analysis of Root Cause:
Lack of control and procedural adherence in the. licensee's program for preparing and implementing Plant Change / Modifications (PC/Ms).
- 3. Basis for Severity Level (Safety Significance): [ Include example from the supplements, aggregation, repetitiveness. willfulness, etc.)
Aggregation of examples and application of Supplement I. C.7. a breakdown in the control of licensed activities involving two violations that are related that collectively represent a potentially significant lack of attention toward licensed activities. The safety significance of reversing the detector inputs to the NIS- ' drawers substantially reduced the safety margin between the TM/LP trip setpoint and the analysis limit even considering the increased TM/LP margin to the trip setpoint due to actual core operating conditions.
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
[by EA#, supplement, and Identification date.] EA 96-249 - Inadequate 50.59 did not identify US0. 7/12/96 EA 96-040 - Boron Overdilution Event. Supplement 1, 1/22/96 EA 95-180 - Inoperable PORVs due to Inadequate PMT. Supplement 1. 8/4/95
- 5. Identification Credit? No The miswired NI drawers were identified through an event (the failure to have the system respond ,'roperly).1. e. the analysis of the data by Reactor Engineering discovered the miswiring of the NI drawers but the error in the drawing should have been discovered in the design control process.
The design error associated with BEACON was identified through routine comparisons of actual plant data with predicted data. This error could have been discovered in the design control process. Enter date Licensee was aware of issues requiring corrective action: 7/30/96
- 6. Corrective Action Credit? Yes Brief summary of corrective actions:
In response to the issue, the licensee adopted corrective actions which included: e For immediate action the licensee prepared a change request for the modification package and channels A.C. and D were reconnected and testing was performed to verify proper NI response. e A root cause/self assessment and training meeting for the Engineering Department emphasizing importance of proper design PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE , WITHOUT THE APPROVAL OF THE DIRECTOR, OE
e . ENFORCEBENT ACTION. - womassa:T i e J verification and importance of questioning attitude. Tape was ) produced of this meeting for future engineering training. : o Procedures (Engineering Quality Instructions) were revised to (1) " require all critical aspects be verified during the PC/M. (2) emphasize that the same level of verification is required for PC/Ms duplicated for the second unit, and (3) reinforce the verification requirements for safety related drawings.
- e' Walkdowns will be conducted (linear NIs) to revise any design documentation and tagging. '
e ASI targets will be established for future trending of ASI during I power ascension. e Require cross-disciplinary reviews of design inputs e Better documentation of assumptions in core design inputs and codes Explain application of corrective action credit: Corrective action appears to be of appropriate scope.
- 7. Candidate For Discretion? NO Explain basis for discretion consideration:
Since actual power conditions did not exceed trip setpoints, no escalation is warranted. Several examples of licensee's declining ' performance in engineering does not warrant mitigation.
- 8. Is A Predecisional Enforcement Conference Necessary? Yes Why:
To determine adequacy of licensee's proposed long-term corrective actions regarding backward looks at modifications performed prior to the Unit 1 outage. This included discussions of other modifications that may not have been independently verified. If yes, should OE or OGC attend? [ Enter Yes or No]: Should conference be closed? [ Enter Yes or No]:
- 9. Non Routine Issues / Additional Information:
I PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
ENFORCEMENT ACTION womassEET , 10.- This' Action is Consistent With the Following Action (or Enforcement Guidance): Previously Issued:' [EICS to provide] [If inconsistent, include:] Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. ' Regulatory Message: . ,
' Positive control must be established and maintained over the design process. with particular emphasis on properly performing independent design verification.
- 12. Recommended Enforcement Action:
SL III
- 13. This Case Meets the Criteria for a Delegated Case. [EICS - Enter Yes or No]
14.- Should This Action Be Sent to OE For Full Review? [EICS Enter Yes or No] If yes why:
- 15. Regional Counsel Review [EICS to obtain]
No Legal Objection Dated: ; 4
- 16. Exempt from Timeliness: [EICS)
Basis for Exemption: Enforcement Coordinator: DATE: I s PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE
. WITHOUT THE APPROVAL Of THE DIRECTOR, OE I
i
- i ENFORCEMENT ACTION WORKSHEET ISSUES TO CONSIDER FOR DISCRETION
.J a Problems categorized at Severity Level I or II.
O Case involves overexposure.or release of radiological material in excess of NRC requirements, a Case involves particularly poor licensee performance. a Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with OI regarding ' the case, whether or not the matter has been formally referred to 01. and whether or not 01 intends to initiate an investigation. A description, as applicable, of the faLts and circumstances that address , the aspects of negligence careless disrcyard, willfulness, and/or ' managament involvement should also be included. O Cirr^nt violation is directly repetitive of an earlier violation. a Excessive duration of a problem resulted in a substantial increase in risk. o Licensee made a conr,cious decision to be in noncompliance in order to obtain an economic benefit. a Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) o Licensee's sustained performance has been particularly good. o Discretion should be exercised by escalating or mitigating to ensure that the proposed civil Senalty reflects the NRC's concern regarding the i violation at issue and tlat it conveys the appropriate message to the ' licensee. Explain. j I PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Enclosure 3 REFERENCE DOCUMEMT CHECKLIST [] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: [] Licensee reports: [] Applicable Tech Specs along with bases: [] ' Applicable license conditions [] Applicable licensee procedures or extracts [] Copy of discrepant licensee documentation referred to in citations such as NRC, inspection record, or test results [] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [] Other miscellaneous documents (List): t 9 PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l J l l
- NI INSPECTION ST. LUCIE-October 7-18. 1996 On July 30. 1996. St. Lucie Unit I was operating at approximately 100 %
power when reactor engineering was analyzing the data taken during power ascension and noted an anomaly in the'results. The data indicated three , of the four excore linear detectors measured core power moving to the i top of the core during power ascension. This was an unexpected 3henomena and did not agree with the trend of the power moving to the sottom of the core indicated by RPS Channel B Linear Range Detector. Control Channel #9 Linear Range Detector, and the BEACON Core Power Distribution Monitoring System. Evaluation of the data collected indicated that RPS Channels A.C.and D could have reversed (rolled) . leads of the top and bottom chambers input to the RPS drawers. The modification performed during the outage associated with this problem was No. PC/M 009-195. During the outage the licensee replaced the power range NI drawers for the Reactor Protection System (RPS) with j new Gamma Metrics drawers. This modification combined the linear power ! range input to the RPS and the logarithmic wide range channel into a 1 single drawer, i.e. reduced the number of drawers on Unit 1 from eight i to four. This modification increased the limits of the instruments j range and replaced aging equipment. i Engineering Verification-Root Cause A design error was responsible for the reverse connection (rolled leads) l on four NI safety related drawers on Unit 1. The Controlled Wiring Diagram (CWD). no. JPN-009-195-001/002 depicted the upper Uncompensated ; Ion Chamber (UIC) connected to the lower UIC input at the NI drawer. The root cause noted that the designer and the lead engineer interpreted ' conflicting information on the existing CWDs and made an assumption. The independent verification may have caught this error had the process been properly performed. The drawings were prepared by the lead i designer with input from the lead engineer. The drawings were then checked by a second designer who had no special knowledge of the NI design. This check was essentially a drafting check. The drawings were i then reviewed by the lead designer and then by the engineering supervisor. Engineering Quality Instructions (01) 1.7. Design Input / Verification. dated July 5,1995, states in part that " Design verification is the process whereby a competent individual, who has remained independent of l the design process, reviews the design inputs. ... and design output to verify design adequacy. This independent review is provided to minimize. ; the likelihood of design errors in items that are important to nuclear i safety." Contrary to this requirement the first reviewer could not be considered as competent because he was not an engineer as required by PROPOSED FNFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE I
k 2 011.7 and the lead engineer as the third reviewer could not be considered to have remained independent of this design project. One of the action items to prevent recurrence was to check all the I&C and electrical PC/M to see.if all the drawing approval signatures could qualify as independent verifiers. The licensee fcund three out of eight open modifications where this was a potential protlem, two of these modifications were electrical and one was I&C. This therefore is not an isolated case. This failure to perform independent verification according to procedure is identified as exam)1e one of violation 50-335/96-17-XX. Failure to Control the Design )rocess According to the Requirements of 10 CFR 50 Appendix B, Criterion III. BEACON Core Power Distribution Monitoring System The licensee had installed BEACON during this refueling outage to replace the older IMPAX code used for in-core flux monitoring. BEACON provided several significant improvements over IMPAX one being real-time flux profile monitoring. This improvement permitted reactor engineering to identify the NIS problem quickly and initiate prompt corrective actions. During power operations, reactor engineering used BEACON to obtain the actual in-core flux profile. The actual in-core flux profile was then used to verify compliance with Technical Specifications and provide calibration information for the excore NIS drawers. As part of these routine surveillances, reactor engineering com] ares actual in-core flux 3rofile to the in-core flux profile predicted )y the core design code.
. Reactor engineering noted larger than normal errors between actual and predicted in-core flux profile. Because BEACON used the same neutronics engine as used in the core design code, reactor engineering could not explain the error and notified the corporate core design engineers. As part of the process to resolve these errors, it was discovered that a simplifying assumption, used to overcome limitations of the IMPAX, was not accounted for in the original design of BEACON. This simplifying assumption was used because the licensee had changed the fuel design to incorporate a longer end cap to prevent debris induced fuel failures.
This longer end cap raised the overall core height by 2.64" causing an offset between detector midplane and actial core midplane. The IMPAX code assumed detector midplane was along core midplane and could not accommodate the 2.64" offset. Therefore, the licensee, after discussion with the fuel vendor (Siemans), used this simplifying assumption to essentially lower the core midplane by 2.64" so that final design output would be referenced to detector midplane: not core midplane. However, the engineer preparing the design in)ut for BEACON was not aware of this simplifying assumption consequently 3EACON was refe-enced to core midplane resulting in an increased error between the core design predicted in-core flux profile and actual in-core flux profile. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
. I i ) . 3 The licensee's root cause evaluation identified lack of cross-discipline review as the significant contributor to this design error. The i inspector concurred with the licensee's evaluation. Engineering Quality ' Instructions (01) 1.7. Design Input / Verification, dated July 5.1995. states in part that " Design verification is the process whereby a competent individual, who has remained independent of the design process, reviews the design inputs. ... and design output to verify design adequacy. This independent review is provided to minimize the l likelihood of design errors in items that are important to nuclear ; safety." Contrary to this requirement, the design inputs were not i adequately reviewed by a competent individual in that the core midplane offset was not identified as a design input for BEACON. This failure to perform an adequate independent design review for the BEACON system is identified as example two of violation 50-335/96-17-XX. Failure to Control the Design Process According to the Requirements of 10 CFR 50. Appendix B. Criterion III. l The safety significance of reversing the detector inputs to the NIS drawers substantially reduced the safety margin between the TM/LP trip l setpoint and the analysis limit even considering the increased TM/LP l margin to the trip set)oint due to actual core operating conditions. ! The safety impact of t1e failure to identify the core and detector midplane offset on TM/LP or LPD safety limits was minimal. CONNECTOR SWAPS AT DETECTOR 6-CHANNEL B All four of the RPS Linear Range Detectors had the connectors reversed ; as previously discussed but the B channel unlike the other three channels was giving the correct data. At the same time that the drawers were being replaced on Unit 1. the detector for channel B (detector no. 1
- 6) was being replaced as a maintenance activity. During connection of the field cables. the connections were reversed for the upper and lower detection chambers, thereby causing the B channel to record properly.
The root cause for the swap of the cables was that the new detector had different labeling than the existing cables. The existing cables were labeled TOP SIG and B0T SIG. and the new detector had A and B. The inspectors discussed this maintenance job with the I&C supervision who had supervised the latter part of this maintenance project. Several opportunities were ) resented to the maintenance personnel, one when the detectors were checced out in the warehouse and a second time when this condition was noted in the field. Maintenance personnel should have resolved the labeling problem by writing a Condition Report (CR) and having a formal resolution. Administrative Procedure No. 0006130. Condition Reports, rev. 4. dated March 22, 1996. Par. 8.1.1.A states in part that "Any individual who becomes aware of a problem or discrepant condition . should initiate a PROPOSED ENFORCEMENT ACTioD - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APP'AOVA' OF THE DIRECTOR, OE
b 4 CR. If doubt exists, a CR form should be initiated". This failure to comply with the requirements of the administrative procedure is identified as violation 50-335/96-17-YY, Failure-to Initiate a Condition Report for Labeling on Safety Related Detectors. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l w 1
t J Violation 1 with two examples. 10 CFR 50 A)pendix B. " Quality Assurance Criteria for Nuclear Power i Plants and uel Reprocessing Plants." Criterion III requires, in aart. l that ..._ design control measures shall-provide for verifying or clecking
.the adequacy of design, such as the >erformance of design reviews...The verifying or checking process shall 3e 3erformed by individuals or groups other than those who performed t1e original design, but who may be from the same organization.
FPL Topical Quality Assurance' Report. TOR 3.0. revision 11. " Design. . Control ." Section 3.2.4. " Design Verification." stated, in part. " Design control measures shall be established to independently verify design . input... Design verification shall be performed by technically qualified !' individuals or groups other than those who performed the design. 1
. Engineering Quality Instructions 1.7 " Design Input / Verification." rev.1.
dated July 5,1995, states in part. " Design verification is the process whereby a competent individual, who has remained independent of the design process, reviews the design inputs. ... and design output to verify design adequacy. ,
- Contrary to the above
- i
- 1. Contrary to the above, on July 30, 1996, it was discovered that a design change (PC/M 009-195) was completed without an independent design verification by a competent individual. Design change PC/M
' 009-195 to install new Gamma Metrics Nuclear Instrumentation drawers was completed by a lead designer and a lead engineer. This design change was independently verified by a second designer who had no special knowledge of the design. A engineering . supervisor approved the design. Neither the second designer or , engineering supervisor had remained independent of the design , process. -
- 2. Contrary to the above, on July 30.- 1996, it was discovered that an independent design review was not conducted for the installation of a new core flux monitoring computer code BEACON. During initial operaticn of BEACON it was found that the code did not compensate for a core mid-plane offset created by a previous core modification, lhe engineer who prepared the design was not aware of the core mid-plane offset and the independent review of the new BEACON code did not identify this omission.
Violation 2 Technical Specification 6.8. Procedures and Programs, paragraph 6.8.1 requires in part that written procedures recommended in Appendix A of Regulatory Guide 1.33 revision 2. February 1978 shall be established, implemented... PROPOSED ENFORCEMENT ACTION NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l > l 2 1 Administrative Procedure No. 0006130, Condition Reports, revision 4 l
. dated March 22, 1996. Paragraph 8.1.1.A states in part that. "Any I individual who becomes aware of a problem or discre) ant condition ...
should initiate a CR. If doubt exists, a CR form s1ould be initiated". Contrary to the above, on July 30, 1996, Instrument and Control technicians installing a plant design change (PC/M 009-15) did not initiate a condition report when they became aware of a discrepant condition concerning incorrectly marked cables. They continued to install the modification and an error was made that resulted in cross-wiring of the nuclear instrumentation system.
~_>
h i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
d 1 The licensee also identified that BEACON was placed into service on Unit I without any
) . benchmarking against IMPAX, the on-line core performance monitoring code BEACON was
- replacing. Instead, BEACON was installed on Unit 2 and benchmarked against CECORE,
, which did not require any modifications to accommodate the core midplane offset. . Engineering Quality Instruction (QI) 3.7, Computer Software Control, revision 1, Section 5.4. requires that SQAl software shall be validated and verified (V&V'ed) in accordance with . r Section 5.6. Section 5.6 states that new software shall be V&V'ed prior to use. V&V 4 includes the use of test cases to ensure the new software produces correct results. Item 4 of i Section 5.6 states that technical adequacy shall be determined by comparing the test case to results from alternative methods such as functionally equivalent and previously vali' dated : software. ' In the case of BEACON, IMPAX would have been functionally equivalent software. Benchmarking BEACON against IMPAX may have identifed the design error , concerning core midplane offset because the two codes would not have yielded the same results. Contrary to this requirement, BEACON was placed into service on Unit I without i benchmarking against IMPAX. This is a Severity Level VI violation. ( r NOTE TO PANEL: This could be considered another example of inadequte PMT as identified in EA 95-182. V&V is the post-mod acceptance test for software. , I d 1 l l
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d I. From: Bruno Ury 6!1 To: JRG [p jd& Date: 6/12/96 1pm Sut W SAPORITO WE JUST FINISHED RECEIVING A BRIEFING FROM THE RESIDENT INSPECTOR AT ST. LUCIE AND THE BRANCH CHIEF WHO ATTENDED THE PUBLIC MEETING AT THE PLANT. THEY ADVISED US THAT SAPORITO SHOWED UP TOWARD THE END OF THE MEETING AND DEMANDED THAT HE BE PERMITTED TO BE HEARD IN THE PUBLIC MEETING. AL GIBSON, THE SENIOR REGION 11 MANAGER IN CHARGE OF THE MEETING, SAID THAT HE WAS READY TO CLOSE THE MEETING AND THAT HE COULD ADDRESS ANY QUESTIONS AFTER HE CLOSED THE MEETING. MR. GIBSON CLOSED THE MEETING AND SAPORITO WENT TO THE PODIUM TO SPEAK. SAPORITO STATED THAT THERE WAS A PROBLEM WITH STEAM GENERATOR PLUGGED TUBES AND HE STATED THAT HE WANTED THE PLANT SHUT DOWN (THE PLANT WAS ALREADY SHUT DOWN FOR AN EXTENDED OUTAGE). SAPORITO SAID THAT THE NRC WAS ASLEEP AT THE SWITCH, THAT THE NRC 15 TOO TRANQUll TO BE THE WATCHDOGS THAT THEY ARE SUPPOSED TO BE, THAT THE NRC N.EEDS TO STEP UP ITS INSPECTIONS OF ST. LUCIE, THAT THE NRC 15 LIABLE IF ANYTHING (AN ACCIDENT?) SHOULD HAPPEN AT THE PLANT, THAT THE ST. LUCIE QA DEPARTMENT IS NOT DOING ITS JOB AND, FINALLY, THAT HE INTENDS TO FILE A WRITTEN 2.206 TO BACK UP HIS VERBAL REQUEST THAT THE PLANT BE SHUTDOWN.
- AL GIBSON THEN ADDRESSED SOME QUESTIONS BY THE PRESS WHICH DID '
NOT SEEM TO ACKNOWLEDGE SAPORITO. 1 i b l 1 l l I
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2 ENFORCEENT ACTION WORKSHEET EICS EETIh iiGTES AE DOCUENTATION OF UEERSTAEING i l II. Civil Penalty Assessment
; A. First non willful SL III violation in 2 years /2 inspections? YES or NO Previous escalated cases:
B. Identification Credit? YES - NO - N/A i 75tC identified? l Licensee identified? j Revealed through an event?* l Prior opportunities? 1 C. Corrective action credit? YES - NO - N/A Immediate corrective actions:
.i e Long term corrective actions to prevent recurrence:
D. Discretion anolied? Yes or No: Reason why. , E. Civil Penalty: F. RE- -- dation for credecisional enforc=-,i conferer.r.e: 3
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l s 3 ENFORCEENT ACTION WORKSEET EICS EETING NOTES AM) DOCUENTATION OF UWERSTAM)ING NOTE: Complete the following infomation for each violation ISSUE: 4 III. Documentation of Enforcement Panel / Caucus Consensus A. Preliminary Severity Level (Prior to Application of my Discretion. From Part I)
- B. Increase Severity Level based on Aggregation?
l C. Increase Severity Level for Repeat Violations?
; (Address requirements of ROI 0903)
D. Increase Severity Level for W111 fulness? E. SEVERITY LEVEL- SUPPlB OIT/SECTION 1 F. Recommended Civil Penalty i G. 'Predecisional Enforcement Conference Necessary? H. Revision to Draft NOV Required? j I. Fomal Review by CE Required? I J. Special Action Items / Nessage to Licensee / Comments ! l l w } .a
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4 s October 2. 1996 HEMORANDUM From: William E. Holland. Team Leader. St. Lucie MR Baseline Inspection f To: Harold O. Christensen. Chief. Maintenance Branch. DRS
Subject:
MAINTENANCE RULE ENFORCEMENT PANEL in accordance with Regional Office Instruction No. 0924. I submit the proposed violations which were identified during a Maintenance Rule Baseline inspection conducted at the St. Lucie plant on September 16 - 20, 1996. I will be available to discuss the proposed violations when the required panel is convened. Excerpts from Draft Inspection Report 50-335, 389/96 13 are included to support the proposed NOVs. The int tial perspective I have about the message we need to send this licensee is: BACKGROUND Preparations for the Maintenance Rule did not start in earnest until after an independent assessment of program implementation was conducted in December 1995. The assessment concluded. in part, that the program did not meet the expectations of the Rule and related guidance, At that time many activities had to be readdressed including: performance criteria, reexamination of historical SSC performance was required monitoring and goal setting was not well defined, etc. Essentially, the licensee started over in preparation of a program for the Rule. However, during the next six months. Other priorities occupied the time of critical personnel (system engineer owners) to prepare for the rule. The program development was essentially implemented during this period by a Maintenance Rule Administrator (Assigned in January 1996) and the licensee's PRA expert. During this time. the licensee reorganized to increase the system engineering staffing from 6 to approximatelt 20 persons. A licensee audit of the program conducted in July 1996, concluded the program was in place and satisfied rule requirements. However, enhancements were necessary and a lack of program elements to evaluate the overall effect of safety functions when removing equipment from service needed innediate attention. The licensee initiated actions in these areas to put a matrix in place for taking SSCs out of service, and enhanced program areas with guidelines by the end of August 1996. The audit also stated that the speed at which the program was implemented resulted in weaknesses in integration of Maintenance Rule processes in the plant daily routine. This inspection verified and validated this statement. MFSSAGE The violations represent weaknesses in implementation of the licensee's program for the Maintenance Rule. They appear to be the result of late program implementation. coupled with reorganization in the system engineering area. Many of the engineers are new to their jobs and have not had time to fully understand their systems and requirements for the rule. Q Management needs to concentrate on the rule implementation and provid 4 4
-_ - . - ~ _ _ _ _ _ . . _ _ . . _.__._ ,
the necessary extra training / oversight to improve program implementation. e e t 4 9
s DRAFTNOTICE OF VIOLATION DRAFT i Florida Power & Light Company Docket Nos. 50-335 and 50-389 St. Lucie Units 1 and 2 License Nos. OPR 67 and NPF-16 During an NRC inspection conducted on September 16 through 20. 1996, violations of NRC , requirements were identified. In accordance with the " General Statement of Policy and l Procedure for NRC Enforcement Actions.* (60 FR 34381; June 30. 1995/NUREG 1600), the violations are listed below: ! A. 10 CFR 50.65 (b) establish the scoping criteria for selection of safety related and i non safety related structures systems, or components to be included within the
. Maintenance Rule program. Scoping criteria includes safety-related structures, systems, or components that are relied upon to remain functional during and following j design basis events to ensure the integrity of the reactor coolant pressure boundary. ;
the capability to shut down the reactor and maintain it in a safe shutdown condition, ' and the capability to prevent or mitigate the consequences of accidents that could l result in potential offsite exposure comparable to the 10 CFR part 100 guidelines: and non safety related structures, systems, or components that are relied upon to
. mitigate accidents or transients or are used in the plant emergency operating .
procedures, or whose failure could prevent safety related structures. systems, and ' components from fulfilling their safety related function, or whose failure could cause a reactor scram or actuation of a safety-related system. I St. Lucie Administrative Procedure. ADM-17.08, IMPLEMENTATION OF 10 CFR 50.65, THE MAINTENANCE RULE. Revision 7 implemented the requirements of 10 CFR 50.65. Appendix B of ADM-17.08 identified those systems and components within the scope of the rule. Contrary to the above. ! As of September 20. 1996, the licensee had not included all systems and components within the scope of the' rule as required. The following systems and components were l not included in the scope of,the program: j l Post Accident Sampling System - This non-safety related system was not j included in Appendix B of ADM 17.08 even though it is used to mitigate the t consequences of accidents and is in the licensee's Emergency Operating (,I Procedures (E0P-03. LOSS OF COOLANT ACCIDENT & E0P-04. STEAM GENERATOR TUBE RUPTURE). Communications System - This non-safety related system was not included in Appendix B of ADM 17.08 even though it is relied upon to mitigate accidents or ! transients, and used in the performance of all Off-Normal Procedures and Emergency Operating Procedures. Unit 1 Service Air System - This non-safety related system was not included on Appendix B of_ADM 17.08 even though its failure could prevent safety-related
-y systems or components from fulfilling their safety-related function. Failure
. of this system which was in use on July 13, 1996, would have resulted in the *
[ [M D failure of the safety related low. pressure safety injection system operating in the shutdown cooling Mode to maintain reactor coolant system temperature within required limits.
O Main Steamline Radiation Monitors - These non safety related. radiation monitors for Units 1 and 2 were not included in Appendix B of ADM 17.08 even though they are used to mitigate accidents, and are used in Emergency Operating Procedures (E0P-04, STEAM GENERATOR TUBE RUPTURE) as an indication that a steam generator tube rupture has occurred. This is a Severity level IV violation (Supplement I) a o e I 1
-. _ . _ . - _________________m___ . _ _ _ _ _ _ ___.. _ _ ______.__._ _______
- - - . . . . .-. ~ - - - . - - - - _ . . . - . . . ,.
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- B. 10 CFR 50.65.(a)(1) requires, in partc that each holder of an operating; license shall >
monitor the performance or condition of structures, systems, or components against licensee established goals. Such goals shall be established comensurate with
. safety.
j
. Contrary to the above,
- 1. As of September 20, 1996, the licensee had failed to establish reliability '
goals or performance crite'ria commensurate with safety for risk significant structures, systems or components for the following systems: Chemical and Volume Control System High Pressure Safety Injection System ' Low Pressure Safety injection System Safety Injection Tanks Main Steam System Main Feedwater System Auxiliary Feedwater System !
' Component Cooling Water System Instrument Air System .
Intermediate Cooling Water System Reactor Protection System Electrical ~ Distribution System ' These systems had been modeled in the licensee's risk determining analysis, with a reliability goal of less'than or equal to 2 maintenance preventable functional failures per 18 months. In establishing these goals, the licensee ;
. failed to demonstrate performance criteria were established comensurate with the critical assumptions used in the licensee's risk determinating analysis.
As such, the licensee's goals for reliability had not been established in a
. manner commensurate with safety.
~
- 2. As of September 20. 1996, the licensee had failed to establish adequate goals I or performance criterla comensurate with safety for risk significant structures, systems, or components in that the condensate cross-tie valves between Unit 1 and Unit 2 which were designated as risk significant by the licensee, did not include availability goals, or reliability goals consistent with the critical assumptions used in the licensee's risk deterinining analysis.
, ThisisaseveritylevelIVviolation(Supplement % j l (
4 C. 10 CFR 50.65 (a)(1) and (a)(2) specify requirements for goal setting and monitoring, and preventative maintenance respectively, for structures, systems, and components within the scope of the Maintenance Rule. St. Lucie Administrative Procedure. ADM 17.08. IMPLEMENTATION OF 10 CFR 50.65. THE
' MAINTENANCE RULE. Revision 7. established procedure for implementation of the requirements of 10 CFR 50.65 (a)(1) and (a)(2).
- 1. ADM 17.08, paragraph 7.8.4 required that cause determinations shall consider any generic implications for structures, systems and components other than the one being evaluated.
- 2. ADM 17.08, paragraph 7.6.4 required that performance monitoring be accomplished by tracking specific (SSC Level) and/or Plant Level Performance Criteria and repetitive maintenance preventable functional failures.
Paragraph 7.11.2.A requires this information be reported in the licensee's Maintenance Rule Quarterly Reports.
- 3. ADM 17.08, paragraph 4.4.3 stated " System owners are responsible for monitoring systems, structures and components for compliance to performance criteria. " Also. Appendix 8 of ADM 17.08 identified the Chemical and Volume Control and Containment Spray Systems as risk significant with specific
. availability performance criteria at the train level.
- 4. ADM 17.08, paragraph 4.4.4 states " System owners are responsible for identifying potential maintenance preventable functional failures and bringing them to the attention of Management and the Maintenance Rule Administrator via the Condition Report Process."
Contrary to the above.
- 1. The generic implications of the failure of a temperature control valve in the Turbine Cooling Water System, which caused a Unit 2 manual reactor trip on June 6,1996, were not considered for similar valves in other plant systems.
- 2. Work Orders 95007753-01 and 95007984-01 performed preventive maintenance on the 4.16 KV Station Blackout Crosstie Breakers, and no unavailability of these breakers was trended against the unavailability performance criteria in the licensee's Maintenance Rule Quarterly Report dated July 9,1996.
Work Orders 95021809 01 and 95023498-01 reported repetitive maintenance preventable functional failures for the 4.16 KV breakers for the pressurizer heater electrical supply which were not shown in the licensee's Maintenance Rule Quarterly Report dated July 9.1996.
- 3. The Chemical and Volume Control System and Containment Spray System owners were not adequately monitoring their systems and components for compliance to performance criteria since the unavailability hours recorded did not include:
Five hours six minutes on July 10 when the 2A charging pump was out of , service. One hundred twenty nine hours 25 minutes between July 22nd and July 27th when the 1A charging pump was out of service,
l l 1 l 4 Eighty hours thirteen minutes between July 13th and July 17th when the I 2A charging pump was out of service. , I Ten hours more than were recorded when the 2A charging pump was out of ! service between August 5th and August 8th. Twelve hours fifty five minutes between August 6th and August 7th when the 2A hydrazine pump, a portion of a Containment Spray train, was out of service, and Seventeen hours twelve minutes on August 18th when the 2A hydrazine pump, a portion of a Containment Spray train, was out of service.
- 4. The system owner did not document the July 25, 1996, potential maintenance preventable functional failure of the 1A Boric Acid Makeup pump on a Condition Report.
This is a Severity Level IV Violation (Supplement I) 1 1 i i l i i
O i Docket Hos.: 50 335 and 50 389 License Nos.: DPR-67 and NPF-16 Report No.: 50 335/96-13 and 50-389/96-13 Licensee: Flordia Power & Light Company Facility: St. Lucie Nuclear Plant. Units 1 & 2 Location: Hutchinson Island St. Lucie County., Florida
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Dates: September 16 - 20, 1996 Team Leader: W. Holland Reactor Inspector. Maintenance Branch Inspectors: W. Bearden. Reactor inspector Maintenance Branch . J. Coley. Reactor inspector. Special Inspection Branch R. Gibbs, Reactor Inspector Maintenance Branch ; W. Rogers. Senior Reactor Analyst l J. Shackelford Reliability and Risk Analyst. NRR
' Approved By: H. Christensen. Chief. Maintenance Branch Division of Reactor Safety i
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?: , EXECUTIVE SlMIARY !
St. Lucie Nuclear Plant Units 1 and'2 f NRC Inspection Report 50 335/96-13 and 50-389/96-13' , This inspection included a review of the licensee's implementation of 10 CFR 50.65, i
" Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants" [the !
Maintenance Rule). The report covers a'l-week period of inspection by inspectors from !
- Region !! and the Office of Nuclear Reactor Regulation. l
- Doerations ,
[ Licensed operators, with some exceptions, understood their' specific duties and ;!
. responsibilities for implementing the Maintenance Rule. Two operators understanding l of duties.and responsibilities 'for implementation of the Rule was weak. Shift i technical advisors were' cognizant and knowledgeable of their roles associated with I the. Maintenance Rule.(Section 04.1).
i Maintenanco Required structures, systems, and components. with the exception of three systems and l radiation monitoring components were included within the scope of the Rule. A ' violation was identified for failure to include all structures. systems, and components within the scope of the Rule as required by 10 CFR 50.65 (b) (Section ; M1.1). -l f
- Plans for performing the periodic evaluation met the requirements of the Rule, in '
- ' . addition, the quarterly report for structures, systems, and components perfonnance .
was considered a positive indicator of the licensee implementation of an assessment l process at a frequency exceeding requirements (Section M1.3). i The approach to balancing reliability and unavailability was reasonable. However, the measure of reliability for risk significant systems did not meet the requirement ; of the Maintenance Rule. Thas, while the overall approach was acceptable, the ; implementation of this approach would not be achievable until such time as acceptable ' p performance criteria for reliability-of risk significant systems was developed a (Section M1.4). The licensee has considered safety in establishment of goals and monitoring for , Systems and Components reviewed. Industry wide operating experience was used and I corrective actions were appropriate. A violation was identified for failure to I follow procedures associated with Rule implementation. Also, some weaknesses'were identified. Examples were: failure to use vendor established acceptance criteria for verifying acceptable contact point resistance in the governor coil for the turbine pump on the Unit 1 'C' Auxiliary Feedwater train, untimely documentation of the cause j ' determination for unit unplanned unavailability, and implementation of licensee procedural requirements associated with the 4.16 Kilovolt breakers (Section IM.6).
- The licensee had adequately addressed 10 CFR 50.63 Station Blackout Rule requirements I and these requirements had been implemented into the Emergency Diesel Generator ;
performance criteria (Section IM.6). For most of the structures, systems. 'and components reviewed, performance criteria ! was established, industry; wide operating experience was considered. appropriate i s
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l 1 i i , trending was being performed, and corrective action was taken when structures, systems, or components failed to meet performance critecia, or when a structure, system, or component experienced a maintenance preventable functional failure. , Structures were being monitored and a systematic program for monitoring had been - established. An item was identified for followup on licensee actions to provide performance criteria for structures after industry resolution of this issue. Several additional examples of the violation for Failure to follow procedures associated with l Rule implementation were identified. In addition, weaknesses were identified. Examples were: performance criteria did not clearly address all maintenance rule functions of the Reactor Protection System, several radiation monitors had not been included in the scope of the Rule, lack of clear definition of system boundaries , associated with steam generator tubes, and numerous deficiencies in the way licensee personnel accomplished monitoring of systems and components to established i performance criteria (Section M1.7). t i Issuance of the Maintenance Rule Administrator periodic memorandum, which provided an i additional barrier to identify maintenance preventable functional failures was-considered a strength (Section M1.7). Plant material condition observed during walkdowns was generally good. Preservation . of equipment by painting was considered to be very good. considering the environment the plant is located in. One example of poor housekeeping (unattended step ladders) ! was observed in Unit 1 safety-related pump rooms (Section M2.1). The licensee's December 1995 assessment, and July 1996 audit provided significant - insight, allowing corrective actions to be taken to institute an adequate program for compliance with 10 CFR 50.65. The assessment and audit provided meaningful feedback to management, and was considered a strength. However, this inspection determined i the program was not functioning well due in part to the short time it has been in place coupled with many new and inexperienced system engineers (system owners) who ; 1
. are not totally familiar with their systems or program requirements (Section M7.1).
Enaineerina The licensee's overall quantitative approach to perform risk ranking for structures. systems, and components in the scope of the Maintenance Rule using the probabilistic safety analysis approach was adequate. A violation was identified for failure to establish performance criteria comensurate with safety. Other weaknesses noted - included; ranking of initiating events and recovery actions not performed in a quantitative manner, re ranking of structures, systems, and components following sensitivity study for unavailability not performed, approach for Bayesian updating for certain systems, structures, and components needed improvement, and expert panel guidance on assessing risk significance of shutdown conditions was weak (Section M1.2). , The overall approach to assessing the impact before taking systems or components out- i of service was adequate. Weaknesses noted were:.the exclusion of Mode 4 operations, j lack of assessments for non. risk significant structures systems, and component : combinations, omissions from the pre-evaluated maintenance risk assessment matrix. ; and inconsistent interpretation of the definition of maintenance activities. The licensee's systematic approach to the development of the pre-evaluated maintenance ! risk assessmed matrix was considered a strength (Section M1.5). , The licensee's predictive maintenance program was being implemented in a manner which i
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. provided the licensee with analysis results to focus on problems prior to. equipment failure. This area was considered a strength (Section E2.1).
~ Most 'of the system engineers interviewed were newly assigned and lacked some system knowledge and historical information for their assigned systems, Although they understood specific requirements of the Maintenance Rule they did not always
- understand how to apply the rule to their systems. The. fact that the licensee assigned systems engineers so. late in the process for implementation of the' rule is viewed as the major contributing factor to the deficiencies noted during this inspection. Four system engineers were knowledgeable of their systems and implementing the Rule requirements in a good manner (E4.1).
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VIOLATION A i M1,1 Scone of Structures SystemsL and Comoonents included Within the Rule
- a. Insnection Scone (62706)
Prior to the onsite. inspection..the inspectors reviewed the ST. Lucie Final Safety Analysis Report, Licensee Event Reports. the Emergency Operating Procedures previous-NRC Inspection Reports, and other information provided by the licensee. The team selected an independent sample of structures, systems. and component's that the team believed should be included within the scope of the rule, which was not classified as. such by the licensee. During the onsite portion of the inspection, the inspectors used this list.to determine if the licensee had adequately identified the structures, systems, and components that should be included in the scope of the rule in accordance with 10 CFR 50.65 (b). b, Observations and Findinas The licensee appointed an expert panel to perform several maintenance rule implementation functions including establishing the scope of the Maintenance Rule. The panel reviewed 106 systems in the plant and determined that 72 were in the scope of the rule. In addition, 54 structures were placed within the scope of the rule. The inspectors reviewed the licensee's data base and verified that all required structures.. systems, and components were included in the rule with the exception of the following: The licensee had not included the Post Accident Sampling System in the scope 1 of the Maintenance Rule. Further review of this system determined that the system would be used during the performance of the sites Emergency Operating
- Procedures to aid in determination of offsite evacuation. Specific examples of this were found in the Emergency Operating Procedures for a Loss of Coolant !
Accident (EOP-03, Revision 14) and Steam Generator Tube Rupture (E0P-04, i Revision 12). This is contrary to 10 CFR 50.65, which requires inclusion of - l SSCs that mitigate the consequences of an accident and are included in plant l E0Ps. The licensee issued Condition Report 96 2278 during the inspection to re-evaluate this system for inclusion in the Maintenance Rule. The licensee had not included the site Communications System in the scope of the Maintenance Rule. Further review of this system determined that the system is used to mitigate the consequences of accidents or transients, and is . vital in the proper performance of all Off-Normal and Emergency Operating l Procedures. A specific reference to the use of the plants Communications System was found in the Station Blackout Crosstie Emergency Operating Procedure (EOP-99, Revision 17). This is contrary to 10 CFR 50.65 which j requires inclusion of SSCs that mitigate the consequences of an accident and l are included in plant E0Ps. The licensee issued Condition Report 96-2278 ! during the inspection to re-evaluate this system for inclusion in the Maintenance Rule. The licensee had not included the Service Air System in the scope of the Maintenance Rule. Review of operator logs determined that the Service Air System Air compressors on Unit I had been crosstied to the Instrument Air ! System on July 13 ,1996 in support of plant shutdown conditions. The
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i l l a I Instrument Air System is included under the scope of the rule. Discussion of this issue with licensee personnel determined that it was licensee policy to 1 routinely crosstie the Service Air System Compressors to the Instrument Air System during outage conditions. Further investigation determined that this configuration could affect the operation of the safety-related Low Pressure Safety injection System operating in the shutdown cooling mode. 10 CFR 50.65 requires inclusion of non safety related systems whose failure could prevent safety related SSCs from fulfilling their safety function and therefore, the i inspectors considered the Service Air System compressors should be included'in i the scope of the rule. . The licensee issued Condition Report 96-2278 during l
' the inspection to re-evaluate this system for inclusion in the Maintenance l Rule.
The inspection team was aware of a history of problems with radiation monitors, and, as a result, a review of the Radiation Monitoring System for scoping within the Maintenance Rule was conducted, even though the Radiation Monitoring System was included in the rule by the licensee. This review _j resulted in the determination that the Main Steam Radiation Monitors had not ') been included in the scope of the Maintenance Rule, even though both the Main j Steam System and the Radiation Monitoring System had been included in the l rule. This deficiency was the result of the lack of specific definition of the boundaries between the two systems. Upon discovery of the deficiency the licensee issued Condition Report 96-2264. Preliminary investigation by the licensee also identified the fact that the Unit 1 Containment Air Radiation Monitors were also not included in the scope of the rule. The Main Steam Radiation Monitors are used to mitigate the consequences of an accident and are included in plant E0Ps. A specific example of their use is in the Steam
' Generator Tube Rupture E0P (EOP 04 Revision 12). This is contrary to 10 CFR l 50.65, which requires inclusion of SSCs that mitigate the consequences of an accident and are included in plant E0Ps. l 10 CFR 50.65 (b) establishes the scoping criteria for selection of safety related and non-safety related structures, systems, or components to be included within the Maintenance Rule program. Scoping criteria includes safety-related' structures, systems, or components that are relied upon to remain functional during and following design basis event.s to ensure the integrity of the reactor coolant pressure boundary, the capability to shut down the reactor and maintain it in a safe shutdown condition, and the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposure comparable to the 10 CFR part 100 guidelines:
and non safety related structures, systems, or components that are relied upon to mitigate accidents or transients or are used in the plant emergency operating procedures. or whose failure could prevent safety-related structures, systems. and
, components from fulfilling their safety related function, or whose failure could cause a reactor scram or actuation of a safety-related system. The deficiencies concerning scoping discussed above are included as examples of a Violation of these requirements, and are cited as Violation 50-335, 389/96-13-01, Failure to Include All Structures Systems, and Components in the Scope of the Maintenance Rule as Required by 10 CFR 50.65 (b).
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= VIOLATION B ;
M1.2 Safety or Risk Determination _ a, Insoection Scone (62706) i Paragraph (a)(1) of the rule requires that goals be commensurate with safety. ' Implementation of the rule using the guidance contained in NUMARC 93-01 requires that safety be taken into account when setting performance criteria and monitoring under . (a)(2) of the rule. This safety consideration would then be used to determine if the l SSCs should be monitored at the train or plant level. The inspectors reviewed the methods that the licensee had established for making these required safety determinations. The inspectors also reviewed the safety determinations that were make for the systems that were reviewed in detail during this inspection,
- b. Observations and Findinas
'b.2 Performance Criteria The inspectors reviewed the licensee's performance criteria to determine if the licensee had adequately set performance criteria under (a)(2) of the maintenance rule ;
consistent with the assumptions used to establish the safety significance. Section 9.3.2 of NUMARC 93 01 recommends that risk significant SSC performance criteria be set to assure that the availability and reliability assumptions used in the risk determining analysis (i.e. PRA) are maintained. PSL elected to use performance criteria for unavailability and reliability different than what was used in the risk determination for many of the risk significant SSCs. The PSA used actual plant
. specific values for unavailability and reliability. PSL selected a performance criterion of two maintenance preventable functional failures (MPFFs) per operating cycle for reliability for almost all risk significant SSCs and used somewhat higher
. unavailability criteria for a number of SSCs. PSL performed a sensitivity analysis that demonstrated that the use of the unavailability performance criteria would not have had a significant impact on total CDF. (i..e. the use of the maintenance rule criteria would have resulted in an approximately 20 t increase in CDF if all of the SSCs were assumed to be simultaneously at the upper end of their allowable values). The inspectors noted i that the licensee did not perform an additional risk ranking to determine that the overall ranking was not adversely affected by the new data. However, based on the final results, the inspectors did not determine that this would have resulted in any new SSCs being categorized as risk significant since (with the exception of Turbine Building HVAC) all of the PSA modelled systems had already been categorized as risk significant. However, at the time of the inspection. PSL had not performed a similar analysis thet demonstrated that the performance criteria used for reliability preserved the assumptions used in the PEA or that the use of the criterion did not have an adverse ' impact on risk ranking. We inspectors noted that there was no relationship established between the criterion and the failure probability assumptions in the PRA since the number of function demands and/or equipment run time were not tracked. Thus, widely different actual SSC reliability estimates (probability of failure upon demand) could result from the same number of MPFfs in a given time period if the number of demands were different. This item is considered to be a violation of 10 CFR 50.65 (a)(1). " Failure to Establish Performance Criteria Commensurate with I P I
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f Safety".-(VIO 50-335. 389/96-13-02). Also, the licensee did not establish appropriate performance criteria for the Unit 2
-to Unit 1 condensate cross tie valves. These valves were categorized as risk '
significant hy calculation PSL-1FJR-94 002, " Risk Significance Determinations of PSL
' Unit 1 Systems." These valves were considered part of the auxiliary feedwater. system
,in the systems summary report. even though they contained a condensate system equipment number. The performanc,e criteria for the auxiliary feedwater system did not include performance criteria, other than 2 MPFFs/18 month period, that would be germane to'these cross-tie valves. However, the cross-tie valves were rarely
.. operated and probably would not be used twice during-any 18 month period. In addition, as previously discussed. MPFFs without correlation to the underlying assumptions used for risk ranking is inadequate. Consequently. this is another
' example of violation 50-335. 389/96 13 02 Failure to Establish Performance Criteria Commensurate with Safety.
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- M1.6 , Gnal settina and Monitorina for' f a)(1) sscs !
a, .Insnertion scone (627c6) '; t Paragraph (a)(1) of the Rule requires, in part, that licensees shall monitor the l
-performance or condition of structures, systems, or components against -l
, licensee established goals, in a manner sufficient to provide reasonable assurance , the SSCs are capable of fulfilling their intended functions. The Rule further , '
- requires goals to be established commensurate with safety and industry-wide operating experience be taken into account, where practical. Also, when the performance or !
condition of the SSC does not meet established goals, appropriate corrective action ,
.shall be taken,
'i The inspectors reviewed the systems and components listed below which the. licensee i had established goals for monitoring of performance to provide reasonable assurance i the system or components were capable of fulfilling their intended function The l inspectors verified that industry wide operating experience was considered, where i practical, that appropriate monitoring was being performed, and that corrective !
action was taken when structures, systems, or components failed to meet goal (s), or , when a structure, system, or component experienced a maintenance preventable functional failure. {
.The inspectors reviewed program documents and records for the six systems or components the licensee had placed in the (a)(1) category in order to evaluate this l area. The inspectors also discussed the program with the Maintenance Rule Administrator, system engineers, and other licensee personnel. (
i' b. Observations and Findinas .
.. 1 b.3 4 16 KV switchaear and Breakers i
The licensee had experienced several repeat Maintenance Preventable Functional 1 failures (MPFFs) involving failure of 4.16 KV Breakers due to floor tripper and latch l switch misadjustments. As a result of these failures the licensee had put these ! breakers in the Maintenance Rule (a)(1) category. The inspector reviewed the { corrective action for these failures, and the goals and monitoring under the (a)(1) , status, and concluded that the corrective action, goals, and monitoring were i appropriate. The inspector also reviewed additional work order data concerning performance of these breakers for the period January 1995 to the beginning of the .
.1'nspection. .This review determined that there were two additional repeat MPFFs and a significant number of breaker unavailability hours, which had not been identified ; in the licensee's Maintenance Rule Quarterly Report as follows: !
e Work. Orders 95007753-01 and 95007984-01 performed preventive maintenance on , the 4.16 KV Station Blackout Crosstie Breakers, and no unavailability of these , breakers was trended against the unavailability perfonnance criteria for these ! breakers in the licensee's Maintenance Rule Quarterly report dated July 4 ' 1996. t i W0s 95021809 01 and 95023498-01 reported repetitive maintenance preventable ! functional failures for the 4.16 KV breakers, for the pressurizer heater ; electrical supply which were not shown in the licensee's Maintenance Rule i-p
3 1 Quarterly report dated July 9, 1996. This was contrary to licensee procedure ADM 17,08. Revision 7. paragraph 7.6.4 and 7.11.2.A. which require performance monitoring be accomplished by tracking specific (SSC Level) and/or Plant Level Performance Criteria and repetitive maintenance
' preventable functional failures, and the documentation of this information the licensee's Maintenance Rule Quarterly Reports. Failure to track repeat MPFFs and SB0 breaker unavailability hours against their performance criteria were identified as examples of Violation 50-335, 389/96-13 03, Failure to follow Procedures for Implementation of the Maintenance Rule.
M1.7 Preventative Maintenance and Trendino for (a)(2) SSCs
- a. Insoection Econe (67706)
Paragraph (a)(2) of the Rule states that monitoring as required in paragraph (a)(1) is not required where it has been demonstrated that the performance or condition of a SSC is being effectively controlled through the performance of appropriate preventative maintenance, such that the SSC remains capable of performing its intended function. The inspectors reviewed selected SCCs listed below for which the licensee had established performance criteria, and was trending performance to verify that appropriate preventative maintenance was being performed, such that the SSCs remain capable of performing their intended function. The inspectors verified that industry wide operating experience was considered, where practical, that appropriate trending was being performed, that safety was considered when performance criteria was established, and that corrective action was taken when structures, systems, or. components failed to meet performance criteria, or when a structure, system, or component experienced a maintenance preventable functional failure. The inspectors reviewed program documents and records for selected structures, systems, or components the licensee had placed in the (a)(2) category in order to evaluate this area. The inspectors also discussed the program with the Maintenance Rule Administrator, system engineers, maintenance supervisors, and other licensee personnel. In addition the inspectors revieved specific program areas based on review of operator logs and equipment out of service logs,
- b. Observations and Findinas b.3 Turbine coolina Water System The licensee had experienced two failures in the Turbine Cooling Water (TCW) System !
on Unit 2, which caused manual reactor trips during the first six months of 1996. i This was below the performance criteria (less than or equal to two failures causing ' manual reactor trips within the past twelve months) established by the licensee in order to keep the system in Maintenance Rule category (a)(2). However, the team determined that this criteria had no technical basis Ts discussed in paragraph M1.2. Even though the TCW System had been classified as (r 62), the system had been reported to management as a system requiring "heigt.cened awareness" in the Maintenance Rule Quarterly Report dated July 9, 1996. Review of the TCW failures determined that they were caused by the failure of the same temperature control valve (TCV 1315). but the failures were due to two different causes (one failure involving electrical logic and one failure involving disconnect of the operator actuator
l c l f i feedback arm from the valve). The inspector reviewed the work order history for valve TCV-13-15 during the previous twelve months, and no additional failures of the ; valve were found. In addition, the inspector reviewed the corrective action for these two failures. The inspector determined that corrective action was appropriate with the one exception: The corrective action for the actuator arm failure had considered similar valves in the TCW system for both units: however, it had not considered similar valves in other plant systems. This is contrary tc, licensee procedure ADM 17.08. Revision 7. paragraph 7.8.4, which requires that cause determinations for failures shall consider any generic implications for structures, systems and components other than the one being evaluated. The licensee issued Plant Managers Action item (PMAI) 96 09-210 when advised of this deficiency. Failure to consider the generic implications of a Maintenance Preventable Functional Failure is included as an example of a Violation 50 335, 389/96-13-03, Failure to follow Procedures for Implementation of the Maintenance Rule, b.6 Unavailability The licensee's general implementation direction to meet this requirement was contained in Administrative Procedure ADM 17.08. " Implementation of.10 CFR 50.65. The Maintenance Rule." Performance criteria was established for all SSCs to set a standard for adequate performance with the performance criteria for each system documented as part of Appendix B to ADM 17.08. Section 7.6.4 of the ADM required, in part, that " Performance monitoring shall be accomplished by tracking Specific (SSC Level) and/or Plant Level Performance Criteria and repetitive maintenance preventable functional failures..." Section 4.4.3 of the ADM stated that the " System owners are responsible for monitoring systems, structures and components for compliance to performance criteria." Further guidance on performance monitoring was provided in System's and Components Engineering Guideline No. SCEG-006, " Guideline for Monitoring Maintenance Effectiveness by Maintenance Rule System Owners." Section 7.3.1.A directec' ystem owners to use the Equipment Out of Service Log to determine the out of service hours. Appendix B of ADM 17.08 identified the Chemical and Volume Control and Containment Spray Systems as risk significant with specific availability performance for Containment Spray trains A/B and Chemical and Volume Control charging pumps A/B/C. The specific unavailability hours were contained in the quarterly system summaries report. The inspector reviewed selected Equipment Out of Service Logs and determined unavailability hours tracked by the system owner associated with the Unit 1 and Unit 2 Chemical and Volume Control Systems were not accurate. Specifically, the unavailability hours did not include: Five hours six minutes on July 10 when the 2A charging pump was out of service One hundred twenty nine hours 25 minutes between July 22nd and July 27th when the 1A charging pump was out of service Eighty hours thirteen minutes between July 13th and July 17th when the 2A charging pump was out of service Ten hours more than were recorded when the 2A charging pump was out of service between August 5th and August 8th.
S i1 As determined through interview, the system owner was using'the working equipment ; i clearance order log to ascertain when the charging pumps were out of service. If E identified in the' log the specific equipment out of service log entry would be r reviewed to determine the actual time the pump was unavailable. . However, this- ; clearance log did not include all of the equipment out of service entries. < 4 The unavailability hours tracked by the system owner associated with the Unit 2 1; Containment Spray System for August 1996 were not accurate. Specifically, unavailability hours for the hydrazine pump were not included as part of the hours _. ,
; The hydrazine pump was considered part of a containment spray train per interview >
i with the Maintenance Rule Administrator and' identified as a key component in the. : system summary for the containment spray (system 7L Based upon interview,' the ! system owner did not know the hydrazine pump was included in the train. Therefore. ! the tracked unavailability hours did not include 12 hours 55 minutes between August t 6th and August 7th, or 17 hours 12 minutes on August 18th when the 2A hydrazine pump j was out of service. ; i Failure to track equipment out of service for comparison to performance criteria as required by procedure 1s identified as an example of Violation 50-335, 389/96-13-03, failure to follow Procedures for Implementation of the Maintenance Rule. j b.7 Ma'intenance Preventable Functional Failures l I i ADM 17.08 designated other performance criteria besides unavailability for monitoring ! risk significant equipment, such as MPFFs, Monitoring of MPFFs was discussed in ! section 4.4.4 of ADM 17.08 which stated " System owners are responsible for , identifying potential maintenance preventable Functional failures and bringing them ; 3
-ta the attention of Management and the MRA via the Condition Report Process." ! ; Section 7,8 further required that a functional failure of a risk significant-
- structure, system, or component, even if the goal or performance criteria was met,
. would receive a cause determination which would be documented as a Condition Report, ,;
I The inspector requested the Condition Reports for several potential.MPFFs identified through review of the Equipment Out of Service and unit specific chronological logs.
- Reports were provided for all but the unexpected tripping of the 1A Boric Acid' Makeup l
, pump on July 25, 1996. Consequently Condition-Report 96-2293 was initiated on , September 19th. Failure of the system owner to initiate a Condition Report prior to . inspector involvement,is identified as an example of Violation 50-335, 389/96-13-03. j Failure to follow Procedures for Implementation of the Maintenance Rule. 1 1 E i l 7.: P R a
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4- I DRAFT lETICF 0F V101 ATIONREVISED 11/12/96
, i St. Lucie Plant
' Inspection Report t,'as. 50 335, 50 389/96-18 ,
A, 10 CFR 50,54(q) requires that nuclear power plant licensees follow and maintain in j effect emergency plans which meet the planning standards of 10 CFR 50.47(b) and the j requirements in Appendix E to 10 CFR Part 50. Section 2,4 of the licensee's Radiological Emergency Plan (REP), Revision 31, states that activation of the i Technical Support Center (TSC) and the Operational Support Center (OSC) will be initiated by the Emergency Coordinator in the event of an Alert, Site Area Emergency, or General Emergency, and that arrangements have been made to staff the TSC and OSC ; in a timely manner. Also specified is that activation of the Emergency Operations Facility (EOF) is required for a Site Area Emergency or General Emergency, and that ' arrangements have been made to activate the EOF in a timely manner, The REP requirements delineated above are implemented by procedure EPIP-3100023E, ;
"On-Site Emergency Organization and Call Directory" Revision 72. The instruction in Section 8,2 of that procedure states that, upon the declaration of an emergency classification, "the Duty Call Supervisor will initiate staff augmentatior." using the
" Emergency Recall System or Appendix A. Duty Call Supervisor Call Directory to notify persons..."
Contrary to the above, from approximately July 22 to October 3,1996, arrangements were not available to staff or activate the TSC, OSC, or E0F in a timely manner because the licensee did not have the capability to implement either the primary method (using the Emergency Recall System) or the backup method (using the Duty Call Supervisor Call Directory) for notifying its personnel to report to the plant during off-hours to staff and activate the TSC, OSC, and EOF,
- i t, o o a 5ever u.y Leve; P! J oletiesi G rel m mt " " U -
B. 10 CFR 50.54(q) requires that nuclear power plant licenlees follow and maintain in effect emergency plans which meet the planning standards of 10 CFR 50.47(b) and the requirements in Appendix E to 10 CFR Part 50. , REP Section 7.2.2, " Training of On Site Emergency Response Organization [ER0] Personnel", states, "The training program for members of the on-site emergency response organization will include practical drills as appropriate and participation in exercises, in which each Individual demonstrates an ability to perform assigned ; emergency functions... For employees with specific assignments or authorities as ' members of ompraency teams, initial training and annual retraining programs will be i provided. Training must be current to be maintained on the site Emergency Team . Roster." REP Section 7.3.2 states, "The Plant Training Manager will ensure that on site Emergency Response Organization personnel are informed of relevant changes in the Emergency Plan and Emergency Plan implementing Procedures [EPIPs] " j Contrary to the above, the licensee failed to adequately implement its training plan for ERO personnel as follows:
- 1. Since at least 1994, the training provided to most members of the on site ERO did not include practical drills and participation in exercises, h ;
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2, In 1994, t licensee failed to provide 1nitial-training or annual retraining I for 17 positions (approximately 92 individuals) identified as part of the on-site response organization. In 1995, the licensee failed to provide initial training or annual retraining for 8 positions (approximately 54 individuals) identified as part of the on site response organization.
; 3. The licensee's training program failed to include initial or periodic retraining on all procedures required to be implemented by ERO personnel in several identified positions. The Plant Training Manager failed to ensure that ERO personnel in several identified positions were informed of relevant changes in procedures EPIP 3100026E, " Criteria for and Conduct of
- Evacuations": EPIP-3100027E. "Re-entry"; and EPIP-3100035E. "Offsite Radiological Monitoring".
- 4. For the calendar year 1995, the licensee failed to remove from the emergency response organization 4 individuals who had not completed retraining as required, and whose qualifications had expired in 1994. The licensee also failed to remove 6 individuals from the emergency team roster effective '
October 6.1996, who had not remained qualified to fill response team requirements as a result of allowing their respirator qualifications to lapse.
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l .- l Isln. shM L aEL M M 2 YEA?!V 2 MSPECTIONS %. or NO
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- 2. CDRRECTNE ACTION: (50% f 4) { }
- 3. LICENSEE PERFORMAMCE: (100% t 4) ( )
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- 4. PRIOR OPPORTUNITY TO IDENTIFY: (100% t) { }
- 5. MULTIPLE OCCURRENCES: (100% t) { }
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4 8 BASE CP: SEVERITY LEVEL: PROPOSED CP: 4 Vs w , e .
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i l-/ EICS' STAFF NOTES FACILITY: MM l i ENF PANEL DATE: 3/g/f4 - ATTENDEES i EICS-NO:
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- ' ltl;gENFCONF CAUCUS ~ IR NO: 4h ( s' ,
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. ~ . . _ _ _. .. . _ . . _ _ _ . . _ _ _ _ . _ _ _ . . _ . _ _.
4
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- MIEVIOUS ESCALATED CASES
- l
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l sJCENSEEJOENTHED: REVEALED THROUGH AN EVENT *: 1 MiWR OPPORTUWTES:
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- 3. C011MCTIVE ACTION CREDff YES or N0 t
i NMEDIATE CAs: l l LASTNG ACTIONS TO PREVENT RECUllRENCE: l
- 4. OfSCMTION APPtJED YES or NO i 6. CIVE PENALTY l
- 6. MCOMENDATION FOR PREDECISIONAL ENFORCEMENT CONFERENCE Y
1 BASE CP: SL: PROPOSED CP: PREDECISIONAL ENFORCEMENT INFORMATION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR, REGION 11
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?
4 g EA NUMBER REQUEST FORM TO: OEMAll OR FAX TO OE FROM: ANNE T. BOLAND REGIONAL CONTACT DATE OF REQUEST ^ SEPTEMBER 29,1995 REGION 11 i i L.CENSEE FLORIDA POWER AND UGHT COMPANY j FACIUTY/ LOCATION ST LUCIE / JENSEN BEACH, FLORIDA UNIT 1
. LICENSE / DOCKET NO(S). DPR-67, 50-335 f ;
LAST DAY OF INSPECTION SEPTEMBER 16,1995 l Of REPORT NO. NONE DATE OF Of REP)RT N/A !
SUMMARY
OF FACTS OF CASE (ANNUAL REPORT FORMAT FOR EATS ENTRY) (MAXIMUM OF 300 CHARACTERS) ll FAILURE TO TAKE PROMPT CORRECTIVE ACTION RESULTING IN THE FAILURE OF A UNIT 1 REUEF VALVE TO RESEAT WITHOUT OPERATOR l INTERVENTION. THE EVENT RESULTED IN APPROXIMi.TELY 4000 GALLONS OF REACTOR COOLANT ACCUMULATING IN THE UNIT 1 PIPE 3 TUNNEL. i i 4 BRIEF
SUMMARY
OF INSPCCTION FINDlHOS'(IF NOT SUFFICIENTLY DESCRIBED ABOVE) i i
- ON AUGUST 10,1995, WHILE PLACING THE UNIT 1 SHUTDOWN COOLING SYSTEM IN SERVICE, THE A LPSI HEADER THERMAL REUEF, UFTED j RESULTING IN THE LOSS OF APPOX. 3500-4000 GALLONS OF COOLANT INTO THE UNIT 1 PIPE TUNNEL. THE ROOT CAUSE OF THE PROBLEM WAS A DESIGN ISSUED ASSOCIATED WITH HIGH BLOWDOWN VALUES; HOWEVER, THE UCENSEE FAILED TO EVALUATE AND CORRECT ;
i ANOMALOUS REUEF VALVE BEHAVIOR ON FEBRUARY 20, MARCH 2, AND MARCH 10,1995, WHICH MAY HAVE PREVENT THE AUGUST EVENT. OVER 100 VALVES WERE EVALUATED FOR THIS CONDUCTION AND 15 REQUIRED REPAlR AND/OR REPLACEMENT. NO SAFETY SYSTEMS WERE DETERMINED TO BE INOPERABLE AS A RESULT OF THIS PHENOMENON. j REASON FOR POTENTIAL ESCALATED ACTION ' 4 j SUPPLEMENT l.C.2.8, A SYSTEM DESIGNED TO PREVENT OR M:TIGATE A SERIOUS SAFETY EVENT BEING DEGRADED TO THE EXTENT THAT A DETAILED EVALUATION IS REQ'UIRED TO DETERMINE ITS OPERABILITY. t . DELEGATED CASE YES X NO ! MED INST PHYSICIAN NUC PHARM RADIOG 1RRAD I WELL LOGGERS ACADEMIC GAUGE MOISTURE DENSITY l OTHER TYPE: CITE SIMILAR CASE: EA NO. SUPPLEMENT 1.C.2.B , i SHOULD DE ATTEND ENF CONF X YES NO NONDELEGATED CASE X YES NO l It NONDELEGABLE TYPE 01 REPORT / WILLFUL COMPLEX / NOVEL DISCP. TION COMM APPROVAL 01 INTEREST SL 1 OR 2 , OTHER REASON: i IS THERE A BASIS TO CLOSE ENFORCEMENT CONFERENCE 7 NO IF YES, EXPLAIN: ENFORCEMENT CONFERENCE TO BE SCHEDULED. l ! EA # ASSIGNED BY OE 95-222 ' DATE: ES ASSIGNED I. N N h I t 2 l
t ESCALATED ENFORCEMENT ACTION PROCESSING SHEET EA 96 236 AND 96 249 FLORIDA POWER AND LIGHT COMPANY - ST. LUCIE NUCLEAR POWER PLANT SL III VIOLATION NO CIVIL PENALTY j VIOLATION OF 10 CFR 50.59 WITH AN UNREVIEWED SAFETY QUESTION STATUS OF PACKAGE: RA SIGNATURE ISSUANCE ON SEPTEMBER 19, 1996 9
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I : ESCALATED ENFORCEMENT ACTION PROCESSING SHEET ; EA 95 180 FLORIDA POWER AND LIGHT COMPANY ; ST. LUCIE NUCLEAR POWER PLANT, UNIT 1 ; SEVERITY LEVEL III PROBLEM FOR INOPERABLE PORVs DISCRETION EXERCISED TO IMPOSE BASE CIVIL PENALTY CONCURRENCE ROUTING: INI11ALS DATL LANDIS: MERSCH0FF: ; GIBSON: EVANS: URYC: RETURN TO BOLAND/ WATSON A5 0F NOVEMBER 13. 1996, WE WILL BE AT DAY lb IN THE PROCESS. STATUS OF PACKAGE: 3 DAY EN ISSUED 11/07/95 READY FOR FINAL SIGNATURE TO BE SIGNED 11/13/95 llELIE1 AUGUST 30, 1995 LAST DAY OF INSPECTION: DATE OF ENFORCEMENT CONFERENCE: SEPTEMBER 25, 1995 , RE-CAUCUS TO CONSIDER CIVIL PENALTY: OCTOBER 6, 1995 l DATE SUBMITTED TO OE- FOR INFORMel REVIEW: OCTOBER 11, 1995 DATE RETURNED FROM OE: NOVEMBER 7. 1995 FINAL SIGNATURE DATE NEEDED TO MEET :
- TIMELINESS GOAL (NON DELEGATED CASE): OVERDUE ,
t l
9 s-i' ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL PREPARED BY: R. Prevatte NOTE: The Section Chief is responsible for preparation of this and its distribution to attendees prior to an Enforcement Panel.(This questionnaire information will be used by EICS to 3repare the enforcement. letter and Notice, as well as the transmittal memo to tie Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit (s): 1 Docket Nos: 50-335 License Nos: DPR-67 Inspection Dates: Julv.30 - Seotember 16. 1995 Lead Inspector: Richard L. Prevatte
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is enclosed. [] This Notice has been reviewed by the Branch Chief or Division Director and each violation incicdes the appropriate level of specificity as to how and when the requirement was violated. [] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g. .- Supplement I.C.2)
I.C.2.8
- 4. What is the apparent root cause of the violation or problem?
Enaineerina evaluation and orioritization of notentiaLeauioment oroblem was not timely.
- 5. State the message that should be given to the licensee (and industry) through this enforcement action.
Imorove orioritization and timeliness of resoonse to olant oroblems.
- 6. Factual information related to the following civil penalty escalation or
n t
~ mitigation factors (see attached matrix and 10 CFR Part 2. Appendix C. Section VI.B.2.): ;
- a. IDENTIFICATION: -(Who identified the violation? What were the- '
facts and circumstances related to the discovery of the violation? Was it self-disclosing? Was it identified as a result of a generic notification?) Licensee dentified' anomalous behavior of safety related thermal , relief va' ves on February 20. March 2. and March 10. 1995. but did not t3ke action until a failure also occurred on Auaust 10. 1995
- and NRC auestioned corrective action.
- b. CORRECTIVE ACTION: Although we expect to learn more information i
regarding corrective action at the enforcement conference. describe preliminary information obtained during the inspection and exit interview. , See item A. What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of. corrective actions? , Initial oroblem was under enaineerina review for several months. , After auestionina by NRC. the oroblem was thorouahly researched ' and corrected. What was the degree of licensee initiative to address the . violation and the adequacy of root cause analysis? Initial - not timely. Final -'aood investiaation and broadened scooe led to review of 1 over 100 relief valves.
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List (incibast violations de specific requirement that may cited be related to date and the the' current issued):violation ; NCV 94-25-01. Inadeauste desian control of NADH suction relief valves. VIO 94-11-01. Enadeauate corrective action for MOV which stalled durina surve11' ance. i r VIO 94-12-01.1E swina bus would not strio on undervoltaae due to ' wirina oroblem 94-08-01. Inadeauate corrective action on waterhammer event. i
- i. - _ _ . - _ _ _ _ . . .
e t Inocerable snubbers and SRV PORV tailoices. 94-08-02. Failure to document above non-conformance. 94-06-02. Inadeauate desian control on Unit 2 charaina oumo t seauence. i 94-06-01. Failure to reoort DG failure. Identify the aaplicable SALP category, the rating for this category and tie overall rating for the last two SALP periods, as well as any trend indicated: Ena. Suocort 1 - 1
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there op)ortunities for the licensee to discover.the violation sooner suc1 as through normal ,
surveillances, audits. 0A activities, s notification, or reports by employees? pecific NRC or industry Problem known but not oursued.
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this ins)ection? If there were, ;
identify the number of examples and ariefly describe each one. NL. 4
- f. DURATION: How long did the violation exist?
Problem has existed on thermal relief valves since initial installation. l l l l 1 z :
1 ADDITIONAL COMMENTS / NOTES:
- 5) Shutdown Cooling Relief Valve Lift A. Background -
On February 28. while placing the 1A SDC train in service, the licensee experienced a lift of 1A LPSI pump suction relief valve V-3483 (see IR 95-04). The valve did not reseat, and the loss of RCS inventory ' was abated by closing LPSI hot leg suction isolation
. valves V-3480 and V-3481, which isolated the valve from RCS pressure. The root cause of the lift was .
determined to be water hammer, which resulted from passing relatively hot RCS fluid through the suction line at high velocity as the LPSI pump was started. As corrective action. the licensee revised OP 1-0410022. " Shutdown Cooling." to change the methodology of starting the LPSI pump to the following: e Shut LPSI pump _ discharge isolation and LPSI
. header isolation valves e Start the LPSI pum) e- Immediately open t1e LPSI pump isolation valve i e Throttle open two LPSI header isolations to 150 gpm per header 4
e Run for 15 minutes i e Start the second pump e Throttle open the remaining LPSI header
. isolation valves to 150 gpm per header e Wait 5 minutes -
e Incrementally open header isolation valves to ! obtain full flow. , The licensee reasoned that this methodology would result in a slow increase in flow, allowing controlled system heatup and minimizing the potential for water > hammer. B. LPSI Discharge Isolation Valve Lift l On August 10, while placing the Unit 1 SDC system in service to support a cooldown required due to inoperable PORVs (see IR 335/95-16). V-3439, the A LPSI header thermal relief, lifted resulting in a loss of a) proximately 3500-4000 gallons of RCS coolant in the Jnit 1 Pipe tunnel. The following timeline was developed from operator interviews, logs and instrumentation data: - 0018'ALPSIpub1pstart(ANPS.NWE.Logr.) . Pressurizer level begins to drop (strip chart i data) l Z m - . - , _ ________i . - -. 7 ,,.
0025 -ANPS directs SNP0 to tour pipe tunnel due to minor reduction in pressurtzer level (ANPS) No-increases in HUT, RWT, etc noted (ANPS) i SNP0 reports no unusual conditions in pipe tunnel 0105 B LPSI pump start (ANPS, NWE, Log) Pressurizer level recovers and oscillates (strip chart) 0140 Cooldown flow established (ANPS, NWE) 0210 Fire watch calls control room, reports water issuing from watertight door isolating pipe tunnel from RAB (ANPS. NWE) ~
. 0215 SDC secured (ANPS, NWE)
Pressurizer level increases and stabilizes (strip chart)- 0226 Floor drain isolation valves (FCV 25-1 through
- 7) noted to be closed on control panel (ANPS, NWE)
Drain valves subsequently. opened (ANPS, NWE) . Flooding in RAB ONOP entered (ANPS) ' Water levels in pipe tunnel weren't dropping due . to clogged floor drains (NWE) !
.0345 Water in pipe tunnel pumped by maintenance '
personnel to floor drains in RAB (ANPS) Operators cycle various isolation valves looking for leak 0611 1A LPSI pump started with NWE observing in pipe tunnel (ANPS) , 0612 NWE identifies V-3439 as passing water (ANPS)
. The licensee concluded that the cause of the relief valve lift was a pressure surge while LPSI aumps were operating in a low-flow condition. The com)ination of RCS pressure (a maximum of 267 psia at the time) and LPSI pump discharge head at essentially no flow (approximately 182 psid) comoined with possible -
perturbations (when starting the pump) was considered enough to challenge the relief valve setpoint (485-515). This condition existed from the time the 1A LPSI pump discharge isolation valve was opened until operators initiated flow through the LPSI header isolation valves. , V-3439 was designed to provide a 10 percent blowdown. which. if. applied to the lower acceptable 11ft setpoint of the valve (485 psig), would require a 48.5 ! psia reduction in pressure to allow reseat. Given these Jarameters, should V-3439 open, RCS pressure would lave to drop to 436.5 )sia to allow valve reseat ; (assuming only a 10 percent ) lowdown). The volume of-the RCS and pre.ssurizer would preclude such a reseat until significant volumes of coolant were lost. The volume of coolant lost during the event was
estimated by the inspector, based upon floor layouts-as displayed on drawings. Given water depths reported by the NWE (up to approximately 14" in some areas), the inspector estimated that ap3roximately 3500 gallons were lost. The CVCS maceup integrator, measuring volume added to the VCT in maintaining pressurizt.c level on setpoint, indicated that 4000 gallons were added to the VCT. The licensee concluded that the closed floor drain isolation valves..HCV-25-1 through 7 (a set of 7 ganged valves) were the result of valve stroke testing in preparation for Hurricane Erin. During testing conducted by control room operators, some of the valves had failed to stroke properly. As a result, the valves were left closed for troubleshooting and were never reopened. OP 1-0010123. Rev 99.
" Administrative Control of_ Valves, Locks, and Switches," required, in step 8.1.6 that "All valve or switch position deviations or lock openings shall be documented in Appendix C, Valve Switch Deviation Log..." The inspector reviewed archived Appendix C logs completed in July and August and control room open A)pendix C logs and found no evidence that HCV-25-1 t1 rough 7 were logged as being out of position.
The failure to enter the valves' closed status into t' e valve deviation log is an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 4). STAR 950917 was initiated to develop a PM for verifying that floor drains were unclogged. The licensee prepared an evaluation of the effects of the subject setpoint/ blowdown values on plant o)eration. JPN-PSL-SENP-95-101, Rev 1. " Assessment of tie Effects on Plant Operation of Lifting the LPSI Pump Discharge Header Thermal Relief Valve." concluded that the subject condition would not have a significant effect on safe plant operation during normal, shutdown, and design basis accident conditions. In reaching this conclusion, the evaluation noted the following: e As flowrate through the relief valve (at lift setpoint pressure) was ap3roximately 40 gpm, the loss of inventory was wit 11n charging system capacity (44 gpm per pump). e During the injection phase of an accident. the LPSI pumps would draw suction from the RWT. thus pressure developed by the pump would not compound a high pressure suct tn source and the relief valve's lift setpoint would not be challenged.
0 e The. relief valve in question discharged to a : floor drain which directed flow to the safeguards room sump. The sump was designed.to be pumped down in level to the- EDT automatically when offsite power is available. Thus, with offsite power available, no flooding hazard-would exist. Under conditions with no offsite power available, the water .~ level in the safeguards room.(after the sump overfilled) would not rise to the level of the HPSI pump motors until ap3roximately 7 hours after the ' lift. Before t11s time elapsed, the licensee reasoned that sump high level alarms would alert operators to the event, allowing operator. . intervention prior to the loss of the HPSI pump. e The licensee noted that, while SDC was-assumed to be ) laced in service during postulated small break _0CAs, ESDEs. and SGTRs (when RCS pressure may have been high enough to have led to a relief valve lift), the FSAR analysis demonstrated that fuel damage (and thus the-release of significant amounts of radioactive material to the RCS) was involved only because t of. extremely conservative assumptions. The evaluation went on to state that "A review of FSAR analysis of small break LOCAs. ESDEs and SGTRs demonstrates that these accidents will not result in fuel damage if assumptions that reflect the actual operating history of the
. plant are applied. Therefore, the radiological consequences of these FSAR accidents will not be increased and the FSAR offsite doses remain bounding." -
The inspector took exception to the licensee's conclusion. The subject passage was included in Section 4 of the evaluation. " Analysis of Effects of Lifting V3439." in a section entitled " Increases in Radiological Consecuences of Design Basis Accidents." The ins Sector founc that, in choosing to neglect design aasis assumptions in their analysis of the event-(specifically, a return to power and fuel failure resulting from the most reactive rod failing to insert), the licensee did not evaluate the increases in.the radiological consequences of design i basis accidents. Rather the licensee evaluated the i radiological consequences of a less significant set of l: accidents and concluded, without providing quantitative results, that the radiological I consequences of design. basis accidents bounded the l noted relief valve lift. While the inspector agreed ) with the licensee's position that the circumstances i assumed in design basis accidents were, l
P probablistically, of low likelihood, the inspector pointed out that the assumptions'were the approved licensing basis of the plant and. as such, provided the appropriate common ground upon which to evaluate the event's significance. The inspector brought this ' to the attention of the licensee, who stated that they would consider the issue. At the close of the inspection period, the licensee had not presented a final position on the issue. As a result this issue will be tracked as an unresolved item (URI 95-15-04. -
" Adequacy of Engineering Evaluation Regarding Unit 1 Loss of Inventory via V-3439"). t On August 12, the inspector requested data on approximately 25 relief valves on both units which comunicated with the RCS in some way. The requested data included lift and blowdown setpoints. tolerances, relief capacity. and normal owrating pressures e experienced by the valves. S1ortly after requesting the information, the licensee informed the inspector that'a team had been formed to evaluate all safety-related relief valve data. The team included members -
from Engineering. Maintenance. Operations. Tech Staff, and Licensing. , The team's review was documented in JPN-SPSL-95-0334. i "St. Lucie Units 1 and 2 Design Review of Safety Related Relief Valves." transmitted to the site by ! letter dated August 30. The inspector found the methodology of the study to be sound, considering worst case combinations of system operating pressures, relief valve setpoint, and blowdown. Relief valves
. were evaluated for their margin to lift and blowdown margin (the difference between reseat pressure and normal system operating pressure). The document '
reported that, of 114 relief valves reviewed. 8 valves on Unit 1 and 5 valves on Unit 2 required further review due to unacceptable margins of lift or blowdown. Corrective Actions were specified for the ! following valves. Unit 1 Valves : 1 e V2324. V2325. and V2326 - Charging Pump ; Discharge Relief. Valves - HEP 107-195M was ) issued to reduce the design superimposed j backpressure from 165 psig to 115 psig. e V2345 - Letdown Relief Valv.e PC/M 108-195 issued to reduce letdown back ressure to 430 psig and to reduce the valve
- blowdown from 25 percent to 15 percent.
e, V3412 - HPSI 1B Discharge Header Relief Valve -
- . i
O EP 115-95 was issued to increase the design setpoint from 1735 psig to 1750 psig and to reduce blowdown from 25 percent to 10 percent. ^ e V3417 - HPSI Pump 1A Discharge High Pressure Header Re' lief Valve -design setpoint increased from 2400 psig to 2485 psig and blowdown reduced from 25 percent to 15 percent. i l e V3468 and V3483 - SDC Suction Relief Valves - STAR 950430 was issued to evaluate new setpoints and blowdown values. Unit 2 Valves e V2345 - Letdown Relief Valve - At the close of the inspection period, an EP was being prepared to implement actions similar to those implemented on Unit 1 for this valve. e V3412 - HPSI 28 Discharge High Pressure Header Relief Valve - At the close of the inspection Period,anEPwasbeingpreparedtoreduce olowdow~n from 25 percent to 10 percent. e V3417 - HPSI Pump 2A Discharge High Pressure Header Relief Valve - At the close of the inspection period, an EP was being prepared to increase the valve's set 3oint from 2400 psig to 2485 psig and to reduce ) lowdown from 25 percent to 10 percent. e V3439 and V3507 - Low Pressure A and B Discharge Relief Valves - At the close of the inspection period, an EP was being prepared to increase the valve's setpoint from 500 psig to 535 psig. As a result of the licensee's investigation, and through discussions with vendors, the licensee . determined that some relief valves had been provided with unacceptably high blowdown values. This was, apparently, due to procedural problems at the vendor's test facility. At the close of the inspection period, the vendor (Crosby) was considering the 10 CFR 21 ! ramifications of the issue. The licensee documented ; the conditions on STAR 951024. The inspector reviewed ' the STAR and noted that it had not been identified as an "N" STAR (indicating a nonconforming conditior.). The inspector brought this to the attention of OC. and ' the condition was corrected. The licensee identified the affected relief valves and segregated them appropriately. The inspector reviewed the licensee's STAR database
n ,m
'{
o for events similar to the subject. event and found the following: 1 I ' STAR 2-950167. initiated February 20. documented
~
e ' the lifting of SDC heat exchanger CCW relief valve SR-14350 when stroking CCW "N" header' , isolation valves closed. Once open, the relief i valve had to be isolated (by closing-an upstream 3 valve'in the process line) to bring about a i l reseat. e STAR 0-950234, initiated March 2. documented the fact that relief. valves had lifted and that.
- blowdown values placed the. reseat pressure of l the valves in the operating ranges of the systems they protected.
e ' STAR 1-950269. initiated March 10. documented. relief valve lifts on the Unit 1 CVCS letdown ' line during evolutions which should not have challenged the valve's setpoint. e STAR 0-950917, initiated August 18. documented , the subject SDC relief valve lift. , In addition to the STARS referenced above. IR 95-05-01 discussed work performed on the Unit 2 CVCS system to prevent letdown line relief valve lifts. The IR also described the failure of the relief valve to reseat (once lifted) due to a blowdown value which placed the '
- reseat pressure below the system's normal operating pressure.
The inspector reviewed the status of the STARS listed above and found them all to be open. The inspector discussed the timeliness of the resolutions to the subject STARS with the licensee. The licensee stated that their focus had been on the methodologies for setting blowdown values on the valves in question, rather than on the appropriateness of the setpoints
' themselves. The licensee offered STAR 950234 as being illustrative of this point. The proposed corrective '
actions included: e Completion of SRV test benches, which would allow the licensee to better set and test SRVs
.for lift set)oint and accumulation It was noted that t1e bench had only limited blowdown test capability.
'e Performing an engineering design basis review of all safety related SRVs to validate or correct setpoints and issue a design document that summarizes the design data.
,'. r - ?
i
- j e Enhancing journeyman training on SRVs.
While the inspector found the. licensee's aroposed. activities prudent it was noted that notling precluded engineering from addressing the setpoint issue earlier in the process. The licensee stated that the STAR was addressed in stepwise fashion and that the maintenance-related items were addressed prior to forwarding the STAR to engineering. The inspector. found that the licensee's corrective ~ actions for the subject event were comprehensive and sound. However, the inspector concluded that the actions could have. reasonably been expected to be performed in a much more timely fashion. The subject i phenomenon was identified as early as February,1994. < and repeated itself on no less than 3 separate systems and on both units, prior to the most recent event. Once focused on the issue, an engineering product of high quality was. developed, and corrective'
. actions initiated. in approximately 2 weeks and identified valves requiring attention in a comprehensive action. 10 CFR 50. @ pendix B required that, for conditions adverse to quality, prompt corrective action be taken to prevent recurrence.
The licensee's failure to take prompt corrective action to the February / March events is a violation (VIO 335/95-15-02. " Failure to Take Prompt Corrective Actions for Repeated Relief Valve Lifts"). 4 i i I 4 f 4
Procosed Violation B
. 10 CFR 50, Appendix B.. Criterion XVI. " Corrective Actions." recuires, in part.:that. measures be established to assure that conditions acverse to quality are promptly. identified.and corrected. -
- Contrary to.the above, prompt corrective action was not taken in'the case of St. Lucie Action. Requests which reported anomalous relief valve behavior and which were initiated on February 20, March 2. and March 10.
4 . 1995. The failure to take prompt corrective action for these conditions led to a repetition of the anomalous behavior on August 10, 1995, when Unit'l relief valve V-3439 lifted and failed to reseat without operator
- intervention. The subject event'resulted in approximately.4000 gallons ;
- 'of reactor coolant accumulating in the Unit 1 pipe tunnel.
This.is a Severity Level III violation (Supplement I). P 0 4 k e i l I e e .v'- ~ - - - e ,,
> j 1-t :
ESCALATED ENFORCEMENT i PANEL QUESTIONNAIRE INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMEN~ 9RE-PANEL PREPARED BY: Mark S. Miller 1 l NOTE: The Section Chief is responsible for preparation of this and its distribution to attendees prior to an Enforcement Panel. (Thisquestionnaire information will be used by EICS to arepare the enforcement letter and Notice, as well as the transmittal memo to tie Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit (s): 1 Docket Nos: 50-335 License Nos: DPR-67 Inspection Dates: March 5 - ADril 1. 1995 !
Lead Inspector: R. L. Prevatte
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate") which includes the
- recommended severity level for the violation is enclosed.
[] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed. . l
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2) ;
I.C.3 I.D.3 IT CAN E CLOSED SI WITHOUT H APPROVAL OF THE REGIONAL ADMINISTRATOR / h
ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE
- 4. What is the apparent root cause of the violation or problem?
The "Droblem" was a loss of shutdown coolina. The aooarent root cause was a misoositionina of V3651 (1B SDC hot lea suction isolation valve) 3v a licensed coerator
- 5. State the message that should be given to the licensee (and industry) through this enforcement action.
Either:- al Timely and effective comoliance with off-normal ooeratina pig.qedures must be affected. or bl Intearity of licensed ooerators is of oaramount imoortance in assessina event root causes
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2. Appendix C. Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation?
Was it self-disclosing? Was it identified as a result of a generic notification?) The event was self-disclosina. The most orobable root cause was determined by the licensee.
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
The licensed coerator deemed to be resoonsible for the event was relieved of licensed activities and susoended with oav Dendina comoletion of the licensee's investiaation. What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? The " violation" in this case is not the loss of shutdown coolina itself and as such the licensee has not taken actions with reaard to the violation. As reaards the orobable root cause for the condition. the licensee oerformed in-deoth reviews to ascertain The that the root cause was not related to eouioment malfunction. 't 9 ooerator in ouestion was relieved of duty within 24 hours of the event.
- THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
l IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE 2 APPROVAL OF TIE REGIONAL ADMINISTRATOR l
- r
t ESCALATED ENFORCEMENT PANEL 00ESTIONNAIRE , a What was; the degree of licensee initiative to address the violation and the. adequacy of root cause analysis? , The licensee was aaaressive and timely in investiaatina the event. A number of reviews were conducted by indeoendent teams and 11dividuals to helo determine the most likely root cause. While t ie evidence suacests stronalv that ODerator error was the root cause. the licensee has fully exolored the technical oossibilities in an attemDt to ensure that an unidentified eauiomant failure is not left in the unit.
- c. LICENSEE PERFORMANCE: This factor takes into account th'e last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued):
%D.2 Identify the applicable SALP category, the rating for this I category and the overall rating for the last two SALP periods, as I well as any trend indicated:
1 00erations - Cateaory 1 l
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there op3ortunities for the licensee to discover the violation sooner suc1 as through normal i - surveillances, audits, QA activities, s noti'.ication, or reports by employees? pecific NRC or industry
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this ins)ection? If there were, identify the number of examples and 3riefly describe each one.
No. The violation acoears to be the result of the actions of a sinale individual.
- f. DURATION: How long did the violation exist?
d The violation occurred in an isolated fashion. ']
--THIS 00CtNENT CONTAINs PREDECISIONAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 3
_ _ _ ._ _ _ _ _ ~_ _ _ .- _. ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE ADDITIONAL COMMENTS / NOTES: On March 4. Unit 1 experienced a loss of shutdown cooling while realigning shutdown cooling trains. The event lasted a) proximately 14 minutes. Initial RCS conditions were 99'F and 247 psia. The!1CS was in a solid water condition, with pressure being maintained through CVCS letdown pressure control. Pe5k RCS temperature during the event was 113 F and peak pressure was 343 psia. At 9:35 p.m., an RC0 was placing the A SDC train in standby after placing the B SDC train in service. OP 1-0410022. revision 19. ' Shutdown Cooling." section 8.2 described the method for placing one SDC train in standby with the other train in service. The methodology (presented in the order specified by the procedure) involved securing the pump in the ain of interest, verifying adequate SDC flow remained, shutting the affecteo Jmp's discharge valve, and then shutting the affected pump's suction valve. The performance of these steps required operation at two different control Janels: the Control Room Auxiliary Console (CRAC) which contained controls for > _ PSI Jump discharge isolation valves, and RTGB 106 which contained controls for L)SI pumps and LPSI pump suction isolation valves. The two panels were located at extreme ends of the Unit 1 control room, requiring operators to i traverse the control room in the course of placing a train in standby. The SDC realignment was being conducted by the Desk RCO. one of two reactor operators on watch at the time. The other reactor operator, the Board RCO, was dedicated to monitoring RCS pressure and controlling letdown flow, as the unit was in a solid water condition. A timeline was established, by the licensee, for the event based upon interviews with the o)erating crew, output from the Sequence of Events Recorder (SOER). and Emergency Response Data Acquisition Display System (ERDADS). Major aspects of the timeline are as follows: 21:41:20 Desk RC0 secures 1A LPSI aump 21:42:20 Annunciator - V3651 (IB LaSI pump SDC suction isolation valve) , closing with IB LPSI pump running ;
- Desk RC0 goes to CRAC to shut A SDC discharge valve i 21:43:20 No SDC flow registered on SDC flow instrument (<1500 gpm) )
Desk RC0 returns to RTGB 106 1 Board RC0 notes pressure increasing
- Board RC0 goes to RTGB 106 and notes annunciator
- Board RCO goes to CRAC to verify valve Jositions Board RCO returns to RTGB 106. then to RTGB 104
- Desk RCO notifies crew of mid-position indication of V3651 21:43:42 Annunciator - V3651 permissive not met - pressure >270 psia Board RCO notes pressure at 320 psia and increases letdown 21:44:35 Annunciator - LTOP anticipatory - pressure >330 psia
--THIS 00CLNENT CONTAINS Pr.EDECISIONAL INFORMATION-.
PRO T REGI NISTRA 4
ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE 21:44:44 Desk RC0 secures IB LPSI pump Desk RCO notes again. and crew acknowledges. dual indication of V3651 21:44:50 RCS peak pressure reached - 343 psia 21:45:00 Board RCO secures 1B charging pump 21:45:41 V3651 open permissive satisfied 21:58:40 SDC > 3000 gpm restored time not precisely established, but sequential based upon interviews The 1icensee concluded that the loss of SDC was the direct result of V3651 closing. ERDADS data, indicating reductions in SDC flow, combined with SOER data would support the conclusion. In considering the cause for the valve closure, the licensee pursued parallel paths which considered electrical 1 malfunction and operator error. ' With regard to possible electrical malfunction, the licensee composed two independent cross-functional teams to consider failure scenarios which might lead to the closure of V3651. The teams analyzed the control circuitry for the valye and postulated electrical faults that might result in valve closure. Field tests for insulation between conductors and conductors and ground were ; conducted with satisfactory results. Additionally. inspections were made of valve limit switch components and physical conditions at the valve. No deficiencies were noted. The two teams concluded that there was no credible electrical fault that could lead to the noted valve closure. The licensee then conducted two additional reviews of the circuitry by engineering personnel not previously associated with the event. Similar conclusions were reached. The inspector reviewed the applicable control wiring diagram for V3651 and determined that the licensee's conclusions were sound. The inspector further concluded that any electrical fault which may I have lead to valve closure must have existed for a period of a] proximately 60 seconds (the valve's stroke time) and then cleared, allowing t1e valve to open. The licensee convened a meeting of the crew on watch during the event. provided a facilitator and ERDADS/SOER data and tasked the crew with creating possible scenarios which could lead to the noted behavior. The crew ' determined that the only credible cause for the event would involve a mispositioning of the key-lock control switch for V3651. followed by a return of the valve's control switch to the open position after the valve had cycled closed. Given the timeline for the event and the results of crew interviews. the only person in a position to make such an error was the Desk RCO. The assumed mispositioning would involve the Desk RCO securing the 1A LPSI pump and attempting to close V3481 (the 1A LPSI pump SDC suction isolation valve) prior to moving to the CRAC to close the 1A discharge isolation valve. 1TCAPN0E S ED SI WITHOUT TH APPROVAL OF THE REGIONAL ADMINISTRATOR 5
ESCALATED ENFORCEMENT PANEL 00ESTIONNAIRE l
'Instead of. closing V3481, the Desk RCO would have to mistakenly operate the 1 control switch for V3651. This would appear credible, as the two switches are !
oriented beside one another. This scenario would allow V3651 to stroke closed l while the Desk RC0 moved to the CRAC and would result in the first annunciator I noted. This scenario would also represent a departure from the governing - l procedure, as the suction valve is listed as the last valve to be operated in placing a SDC train in standby. The scenario in question would further require the Desk RC0 to realize his' error upon returning to RTGB 106 and return the control switch for V3651 to the open position in an attempt to correct the error. Given that RCS pressure exceeded the pressure interlock associated with V3651, the valve would fail to
~
cycle completely open until pressure was reduced below the interlock setpoint. This would explain the dual position noted by both the Desk RC0 and the crew. The Desk RC0 was presented with the licensee's conclusions and has maintained ' that he did not misposition V3651. The licensee relieved the Desk RCO of licensed duties and placed him on suspension with 3ay while investigations were being conducted. As data began to indicate tlat electrical malfunction was not credible, the licensee withdrew the Desk RCO's site access. SAFETY CONSEQUENCES The safety consequences of this event were minor. TS were not violated. TS 3.4.1.4.1 requires, in Mode 5 with RCS loops filled, at least one shutdown cooling loop be operable and either one additional shutdown cooling loop be operable or secondary side water level of two steam generators be greater that 10% of narrow range indication. During this event, both shutdown cooling loops were operable. RCS loops were filled. and both steam generators had water level greater than 10% of narrow range indication. TS 3.4.1.4.1 also requires that at least one shutdown cooling loop be in operation. With no shutdown cooling loop in operation. Action Statement b. allows one hour to
. initiate corrective action to return the required shutdown cooling loop to operation. In this event, one shutdown cooling loop was restored to operation in about 14 minutes.
TS 3.4.13 requires, in Mode 5. that two power o)erated relief valves (PORVs) be operable, with their setpoints selected to tie low temperature mode of operation and a setpoint of less than or equal to 350 psia during isothermal conditions when the temperature of any RCS cold leg is less than or equal to i 193 degrees F. During this event, two PORVs were operable with their setpoints selected to the low temperature mode of operation and a setpoint of 346 psia. The PORVs each have a capacity of 321 gpm, and are designed to prevent RCS P/T limits from being exceeded during design basis overpressurization events due to mass or energy addition to the RCS. In addition, the two shutdown cooling relief valves each have a capacity to relieve the flow from three 44 gpm each charging pumps. 1i CAN NO BE D SCLOSED 51 W THOU TH APPROVAL OF THE REGIONAL ADMINISTRATOR 6
ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE DRAFT VIOLATIONS A. Technical Specification (TS) 6.8.1.a recuired that written procedures be established implemented, and maintainec covering the activities recomended in Appendix A of Regulatory Guide 1.33. Revision 2. February 1978. Appendix A. paragraph 1.d. includes administrative procedures for procedure adherence. Appendix A. paragraph 5. includes Abnormal Operating Procedures. Procedure 015-PR/PSL-1. Revision 60. " Preparation. Revision. Review / Approval of Procedures." Section 5.13.2 stated that all procedures shall be strictly adhered to. Off-Normal Operating procedure 1-0030131. Revision 59. Plant Annunciator Summary." requires, in part, that upon receiving annunciator R-30. "LPSI PP 1B RUNNING /V-3651/3652 CLOSING." operators try to o)en Shutdown Cooling valves and, if no response is obtained, stop t1e IB Low Pressure Safety Injection Pump. Contrary to the above, on March 4. 1995, at 9:42:20 p.m.. the R-30 annunciator was received in the Unit I control room without operators i aroperly verifying Shutdown Cooling valve positions or securing the 1B i
. PSI pump. As a result. Shutdown Cooling flow was lost when V3651 1 achieved a closed position approximately one minute later. The IB Low l Pressure Safety Injection Pump was not stopped until approximately 2 ;
minutes and 22 seconds after the annunciator was received. j The loss of Shutdown Cooling resulted in a temperature excursion from 99 l F to 114 F and a pressure excursion from 247 psia to 343 psia. This is a Severity Level IV Violation (Supplement 1). l B. Technical Specification (TS) 6.8.1.a recuired that written procedures be l established, implemented, and maintainec covering the activities - l recommended in Appendix A of Regulatory Guide 1.33. Revision 2. February 1 1978. Appendix A. paragraph 1.d. includes administrative procedures for procedure adherence. Appendix A of Regulatory Guide 1.33. Revision 2. paragraph 3.c. includes operating procedures for the Shutdown Cooling system. Procedure 01 5-PR/PSL-1. Revision 60. " Preparation. Revision. Review / Approval of Procedures." Section 5.13.2 stated that all 3rocedures shall be strictly adhered to. Procedure OP 1-041022. Revision 19. " Shutdown Cooling." paragraph 8.2 required that the Shutdown Cooling Train A be returned to a standby condition by, sequentially, stopping the 1A low Pressure Safety Injection Pump, ensuring adequate Shutdown Cooling flow, closing V3206. and closing V3481.
--THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
PROV T REGI ADMINIST 7
ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE Contrary to the above on March 4. 1995._ Shutdown Cooling Train A was improperly placed in a standby condition when V3651 was operated in lieu of V3481. Additionally, the valve was manipulated out of sequence with the noted procedure in that it was operai ?d prior to closing V3206. As a result, shutdown cooling flow was lost Tor doout 14 minutes while the unit was in Mode 5. This is a Severity Level IV. Violation (Supplement 1). Comments on DRAFT VIOLATIONS Above With regard to VIO A, this would give us an opportunity to take enforcement
. action without explicitly determining root cause. It would also send a message that the crew. not an individual, is responsible for safety. The potential downside of this approach is that the " Purposes and Discussion" portion of the ON0P includes words like...
"This procedure provides an informative guide to operations personnel. ..The actions listed are intended to be a guide. . .and are not intended to be a substitute for good judgement..."
As a result, the licensee could make the case that the actions stated in the ONOP constitute " guidance" and so.are not explicitly binding on the operators. Our response would then be that, by responding to the first annunciator PROMPTLY. the event may have been avoided. We could cite a failure to follow OP 1-0410022 (VIO B above), in that V3651 was shut - mistakenly, in lieu of V3481 - out of the order spec.ified in the procedure; however, this may not really speak to the root cause or significance of the event. In either case, to cite at all based upon operator error would be to decide that operator error was the root cause without knowing conclusively. If we are to conclude that operator error was the root cause, it would seem to me that the larger issue is operator integrity, as the operator in question continues to proclaim innocence. As such. it might be better to send a message which speaks to integrity by acting on the individual's license. A letter of reprimand or something similar might be the way to go.
^ '" '"
" "ITN N $E D SCL ED 0 1 WI HOUT TH APPROVAL OF THE REGIONAL ADMINISTRATOR 8
. l
. l o i ESCALATION AND MITICATION FACTORS (57 FR 5791. February 18. 1992) l IDEhTIFICATION CORRECTIVE LICENSEE PRIOR MULTIPLE DURATION ACTION PERFORMANCE OPPORTUNITY TO OCCURRENCES IDENTIFY
+/- 508 +/- 508 +/- 1005 + 1001 + 1005 + 1005 Licensee Timeliness of Current Licensee should HJ1tiple Used for identified (M) corrective violation.is an have identified examples of significant t
[To be applied action (M) isolated violation violation regulatory even if [Did NRC have failure that is sooner as a identified message to licensee could to intervene to inconsistent result of prior during licensee. (E) have accomplish with licensee's opportunities inspection identified the satisfactory good such as audits (only for SL 1. Violation short-tenn or performance (M) (E) 11 or 111 sooner) remedial action violations) (E) (E)1 NRC identified Promptly Violation is Opportunities OTHER CONSIDERATIONS (E) developed reflective of available to schedule for licensee's poor discover 1. Legal aspects and potential long term or declining violation such litigation risks corrective performance (E) as through action (M) prior 2. Negligence, careless dis-notification regard, willfulness and - (E) sanagement involvement Self- Degree of Prior Ease of earlier 3. Economic, personal or i disclosing licensee performance and discovery (E) corporate gain ! (M 25% if initiative (M) effectiveness ! there was [To develop of previous 4 Any other regulatory frame- ' initiative to corrective corrective work factors that need to be identif actions and action for considered: pending action cause) y root similar rootcause) with regard to licensing, violations cm mission meeting, or press conference. Licensee Adequacy of the SALP - Period of time identified as root cause Consider: between 5. What is the intended message a result of analysis for SALP 1 - (M) violation and for the licensee and the generic the violation SALP 2 - (0) notification industry? notification (M) SALP 3 - (E) received by (M) licensee (E) .- -... .- NOTES - - --- Comprehensive Prior Similarity corrective enforcement between the action to history violation and prevent including notification occurrence of escalated and (E) similar non-escalated ! violation (M) enforcement l Immediate level of corrective management action not review the taken to notification restore safety received (E) and compliance (E) SAFETY SIGNIFICANCE: In determining the safety significance of a violation in conjunction with the enforcement process, the evaluation should consider the technical safety significance of the violation as well as the regulatory significance. Consideration should be given to the matter as a whole in light I of the circumstances surrounding the violation. There may be cases in which the technical safety I significance of the matter is low while the process control failure (s) may be significant, and, therefore, the severity level determination should be based more on the process control failure (s) than on the technical safety issue. The following factors should also be considered: 1) Did the violation actually or potentially impact public health and safety? 2) What was the root cause of the violation?
- 3) 15 the violation an isolated incident or is it indicative of a programatic breakdown? 4) Was management aware of or involved in the violation? 5) Did the violation involve willfulness?
- 't l r 1 /
l ENFORCEMENT ACTION WORKSHEET ) INADEQUATE CONFIGURATION HANAGEMENT PREPARED BY: Mark S. Miller DATE: June 25, 1996 NOTE: 'The section Chief of the responsible Division is responsible for preparation of this EAW and its distribution to attendees prior to an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e-mail (ENF.GRP, CFE, DEMAIL. JXL. JRG, sHL. LFD: appropriate RII DRP DRs; appropriate NRR, NMss).
- A Notice of Violation (without "boilerplate") which includes the recomended severity level for the violation is required. Copies of applicable Technical specifications or license conditions cited in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed.
This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level. of specificity as to how and
'when the requirement was violated. ,
Signature Facility: , Unit (s): ' Docket Nos: License Nos: Inspection Report No: Inspection Dates: Lead Inspector:
- 1. Brief Summary of Inspection Findings: [Always include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then, either' summarize the inspection findings in this section or reference and attach sections of the inspection report. inspectors are encouraged to utilize the Noncompliance Information Checklist provided in Enclosure 4 to ensure that the information gathered to support the violation ;
is complete.] A number of unrelated findings over three inspection periods has indicated that the licensee has inadequately managed configuration control, particularly in the area of ensuring that design changes are reflected in procedures. A number of annunciator response summary arocedures have been found to include erroneous information, and several - lave been tr6ced back to the hardware changes which rendered the procedures inaccurate. While none of the individual occurances (with respect to annunciators) presented high safety significance, the findings have illustrated an ongoing failure to properly factor design changes into procedures due, primarily, to a failure to identify, up front, the procedures which would be affected and to properly track the procedure revisions to closure. In addition to the annunciator issues, one drawing was identified as i having been overlooked in the design change process, and one procedural deficiency, identified by the licensee is identified. The licensee-
/ l PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE ,
l
ENFORCEMENT ACTION NORKSEEET identified issue involved a failure to include prerequisites'in a procedure which would have been required to ensure the validity of the licensee's full core offload spent fuel pool heat load calculations. Core offload began before the failure was identified, and 7. assemblies were offloaded before operations were secured and corrective actions taken. . See attached IR feeder and proposed NOV for details. 4 4 4 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
O' ENFORCEMENT ACTION - woarsusar
- 2. Analysis of Root Cause:
Lack-of formality in the licensee's program for preparing and
, implementing Plant Change / Modifications (PC/Ms), which did not explicitly require that affected procedures be identified and reviewed / changed during the development and execution of PC/Ms.
- 3. Basis for Severity Level (Safety Significance): [ Include example from the supplements. aggregation, repetitiveness, w111 fulness, etc.]
. Aggregation of examples and application of Supplement I. C.7. a
-breakdown in the control of licensed activities involving a number of violations that are related that collectively represent a potentially significant lack of attention toward licensed activities.
While safety significance with respect to annunciator response procedure
' issues is difficult to assess. the number of examales identified (both in the citation and in addition to the citation) ay NRC indicate that a weakness in incorporating design changes into procedures has existed for some time. Additionally, the licensee-identified portion of the violation (involving a failure to include calculational assumptions as prerequisites in operational procedures) represented a challenge to the Spent Fuel Pool's ability to remove the decay heat associated with a full core offload. l
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
[by EA#, supplement. and Identification date.) EA 96-040 - Boron Overdilution Event. Supplement 1. 1/22/96 EA 95-180 --Inoperable PORVs due to Inadequate PMT. Supplement 1. 8/4/95
- 5. Identification Credit? No The configuration management issue was raised by NRC initially in March.
1996, as walkdowns of annunciators indicated that inaccuracies were frequent in annunciator response procedures. The issue grew through j 5/96. with additional examples identified and the sources of some of the inaccuracies (PC/M implementation) being identified by NRC. Licensee corrective action began in late April, when we identified drawing errors i and additional annunciator response procedure errors. Enter date Licensee was aware of issues requiring corrective action: [4/96]
- 6. Corrective Action Credit? Yes Brief summary of corrective actions:
In response to the issue, the licensee adopted corrective actions which included: e = Implementing design control processes from Turkey Point. which provided more positive control over the initial reviews and PROPOSED ENFOMCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE e
ENFORCEBGNT ACTION WORKSHEET documentation of required actions for PC/Ms. e Performing reviews of all Unit 1 outage related PC/Ms to ensure that required procedural changes were identified. e- Requiring that all PC/M paperwork for modifications installed during the current Unit 1 outage be closed out prior to returning the affected system to service. e Revalidating open items from previous PC/Ms on both units and establishing timelines for closure of the open items. e Initiating a vertical slice inspection of selected. PRA-significant (EDGs HPSI, and CCW) systems to ensure that the systems were properly installed and that procedure.; were adequate. Explain application of corrective action credit: Corrective action appears to be of appropriate scope.
- 7. Candidate For Discretion? Yes Explain basis for discretion consideration:
Licensee's performance has been considered superior in the past.
- 8. Is A Predecisional Enforcement Conference Necessary? No
- 9. Non Routine Issues / Additional Information:
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
.a.
. ENFORCEMENT ACTION womasusse
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: [EICS to provide] [If inconsistent. Include:]
Basis for Inconsistency With Previously Issued Actions (Guidance)
, 11. Regulatory Message:
Positive control must be established and maintained over the design 1 change process. with particular emphasis on ensuring that design, features and constraints are properly incorporated into procedures and
- drawings.
- 12. Recommended Enforcement Action:
SL IV i l
- 13. This Case Meets the Criteria for a Delegated Case. [EICS - Enter Yes or No] {
l
- 14. Should This Action Be Sent to OE For Full Review? [EICS - Enter Yes or No]
If yes why: 1
- 15. Regional Counsel Review [EICS to obtain]
No Legal Objection Dated: ;
- 16. Exempt from Timeliness: [EICS)
Basis for Exemption: Enforcement Coordinator: . DATE: PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC D!SCLO9URE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
ENFORCEMENT ACTION WORKSHEET ISSUES TO CONSIDER FOR DISCRETION. o Problems categorized at Severity. Level I.or II.
- o. Case involves overexposure or release of radiological material in excess of NRC requirements.
o Case involves particularly poor licensee performance. o Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with 01 regarding : the case, whether or not the matter has been formally referred to 0I. i and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included. '
.O Current violation is directly repetitive of an earlier violation.
o Excessive duration of a problem resulted in a substantial increase in risk, a Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. o Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) o Licensee's sustained performance has been particularly good. o Discretion should be exercised by escalating or mitigating to ensure that the proposed civil Senalty reflects the NRC's concern regarding the violation at issue and tlat it conveys the appropriate message to the licensee. Explain, l l 1 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l
Enclosure 3 REFERENCE DOCUMENT CHECKLIST [] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.:
^
[] Licensee reports: [] Applicable Tech Specs along with bases: [- ] Applicable license conditions [] Applicable licensee procedures or extracts
.[ ] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results
[] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability ; [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [] Other miscellaneous documents (List): f PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE , WITHOUT THE APPROVAL OF THE DIRECTOR, OE
f Inspection Report-96-04 identified several potential configuration l
. control weaknesses involving-inaccuracies in control room annunciator. i response sumaries and engineering drawings. Of the deficiencies noted, one was tied to an inadequacy in the implementation of a PC/M. i Unresolved Item 96-04-05 Configuration Control Management." was opened to track the issue while the inspection scope was expanded. Inspection 1 Report 96-06 documented additional deficiencies identified during-system walkdowns, which were the result of PC/M implementation ,
inadequacies. During the current inspection period, additional PC/M i implementation issues were identified. The individual issues are as follows: , IR 96-04 documented the fact that, on January 6. 1995, the i e ' licensee closed out PC/M 109-294 [Setpoint change to the Hydrazine Low Level Alarm (LIS-07-9)] without assuring that a;fected , procedure ON0P 2-0030131. " Plant Annunciator Sumary", was ' revised. This resulted in annunciator S-10 HYDRAZINE TK LEVEL LO ' showing an incorrect setpoint of 35.5 inches. e IR 96-06 documented the fact that, on May 16, 1994, the licensee closed out PC/M 341-192 [ICW Lube Water Piping Removal and CW Lube ; Water Piping Renovation]. The as-built Dwg. No. JPN-341-192-008 ' was not incorporated in Dwg. No. 8770-G-082. " Flow Diagram Circulating and Intake Cooling Water System" Rev 11. sheet 2 . issued May 9. 1995 for PC/M 341-192. This resulted in Dwg. No 8770-G-082 erroneously showing valves I-FCV-21-3A & 3B and l associated piping still installed. e IR 96-06 documented the fact that, on February 14. 1994, the : licensee closed out PC/M 268-292 [ICW Lube Water Piping Removal and CW Lube Water Pi31ng Renovation] without assuring that i affected procedure 040P 2-0030131. " Plant Annunciator Sumary", was revised. This resulted in annunciator E-16 CIRC WTR PP LUBE WTR SPLY BACKUP IN SERVICE incorrectly requiring operators verify - the position of valves MV-21-4A & 4B following a SIAS signal using control room indication. These valves no longer received a SIAS , signal, were deenergized and had no control room position indication, e This inspection report documents the fact that. on October 28, 1992, the licensee closed out PC/M 275-290 [FIS-14-6 Low Flow Alarm and " Manual" Annunciator Deletions] without assuring that affected procedure ONOP 2-0030131. " Plant Annunciator Sumary", was revised. This resulted in safety-related annunciators LA-12 ATM STM DUMP MV-08-18A/18B OVERLOAD /SS ISOL and LB-12 ATM STM DUMP MV-08-19A/19B OVERLOAD /SS ISOL incorrectly requiring operators to check the Auto / Manual switch or switches at RTGB-202 and PACB for the MANUAL position. The relay contacts which energized these i annunciators based on switch position were removed to eliminate . - nuisance alarms. e During the current inspection period, the licensee identified the fact that assumptions made in the heat load calculation supporting
- the Unit 1 full core offload were not appropriately factored into PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE I
the applicabic procedure. Specifically, PC/M 054-196. supplement 0, St. Lucie Unit 1 Cycle 14 Reload." included, in Attachment. 8. operational limitations which resulted from the heat load calculation performed to support the full core offload. These included: e Ensuring that initial SFP temperature was less than or equal to 106 F.
- Ensuring that the reactor was subcritical for at least 168 hours prior to commencing the offload.
e Verifying that the SFP high temperature alarm, which annunciated in the control room, was operable. e' Verifying that two SFP cooling pumps were in operation. , e Verifying that CCW flow to the fuel pool heat exchangers was ; maintained at approximately 3560 gpm when two SFP cooling pumps were operating. On May 12. the licensee's 0A organization identified these deficiencies after the offload of 7 fuel assemblies. The defueling evolution was subsequently stopped, and the l prerequisites were added to OP 1-1600023. " Refueling Sequencing Guidelines." as revision 62 to the procedure. Only four exam)les of inaccurate annunciator response summaries are i cited above; tiose being inaccuracies for which the inspectors determined which PC/M resulted in the inaccuracies. IR 96-06 summarized recent NRC findings in this area, and stated that ten examples of alarm ! setpoint inaccuracies and 18 other (e.g. wrong sensing element, wrong i action directed) inaccuracies in the Annunciator Response Summaries had been identified in both units' ICW and CS systems. 10 CFR 50 Appendix B. Criterion III. " Design Control." requires, in part. that measures be. established to ensure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The licensee's Topical Quality Assurance Report. TOR 3.0 revision 11. " Design Control," included the following provisions: e Section 3.2.2. " Design Change Control." stated, in part. " Design changes shall be reviewed to ensura that implementation of the design change is coordinated with any necessary changes to operating procedures..." e Section 3.2.4. " Design Verification." stated in part. that
" Design control measures shall be established to inde)endently verify that-design inputs, design process and that t1e design inputs are correctly incorporated into design output."
The inspectors concluded that the examples cited above failed to satisfy these criteria and, therefore, constituted a violation (VIO 96-08-XX.
" Failure to Adequately Manage Configuration Control"). In the cases of PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
. procedural inadequacies brought on by the implementation of PC/Ms, the inspectors concluded that a lack of detailed preimplementation reviews >
existed with respect to the impact of a given PC/M on procedures. While preparing PC/Ms. the licensee included a review for impact to other organizations' procedures and documented potential impacts on PC/M review forms: however. this documentation amounted to a "yes" or "no" determination, as opposed to specifying the procedures which required revision. As a result, no formal process tracked the completion of formally specified actions. The licensee's 0A organization aerformad an audit of this area and documented their findings in OS.-PCM-96-11. "PC/M Design Control." The licensee found the following with regard to the process: . e Plant procedures and instructions did not adequately define the review and comment process by plant departments impacted by PC/Ms or the resolution to those comments.
- Plant procedures and instructions did not adequately address the identification of plant procedures impacted by PC/Ms.
e Plant procedures and instructions did not adequately address the review of Safety Evaluations for impact on plant procedures and instructions (this appl'ad to Safety Evaluations which included ' conditions to ensure that the assumptions in the evaluations were maintained valid). The inspectors found the licensee's findings to be in general agreement with observations made by the NRC. In response to the issue, the licensee adopted corrective actions which included-e Implementing design control processes from Turkey Point, which provided more positive control over the initial reviews and documentation of required actions for PC/Ms. e Performing reviews of all Unit 1 outage related PC/Ms to ensure ; that required procedural changes were identified. e Requiring that all PC/M paperwork for modifications installed during the current Unit 1 outage be closed out prior to returning l the affected system to service. ! l e Revalidating open items from previous PC/Ms on both units and establishing timelines for closure of the open items. e Initiating a vertical slice inspection of selected. PRA- i significant (EDGs. HPSI, and CCW). systems to ensure that the i systems were properly installed and that procedures were adequate. l l The inspector concluded that the licensee had moved aggressively to address the PC/M issues discussed above and to ensure that the as-built configuration of.the plant was adequate. The overall adequacy of the licensee's actions will be determined in followup inspections to the PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
h violation described above. .i r k 4 a i i i-i - 1 1 4 i 4 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i:
. . -o. . , .
10_ CFR 50 Appendix Bt " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," Criterion III required, in part, - that measures be established to assure that applicable regulatory requirements and the design basis for those structures, systems, and ' components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. FPL_ Topical. Quality Assurance Report, TOR 3.0 revision 11. " Design Control." - Section 3.2.2, " Design Change Control." stated, in part, " Design changes shall be reviewed to ensure that implementation of the design change .is - coordinated with any necessary changes to operating procedures..." " Section 3.2.4, " Design Verification," stated, in part, that " Design ; control measures shall be established to independently verify the design inputs, design process, and that the design inputs are correctly incorporated into design output." Contrary to the above: 1, On January 6, 1995, the licensee failed to coordinate a design " change with an operational procedure change when PC/M 109-294 [Setpoint change to the Hydrazine Low Level Alarm (LIS-07-9)] was ' completed without assuring that affected procedure .0NOP 2 0030131,
" Plant Annunciator Summary," was revised. This resulted in annunciator S-10. "HYDRAZINE TK LEVEL LO," showing an incorrect setpoint c,f 35,5 inches in the procedure.
- 2. On May 16, 1994, the licensee failed to perform an adequate independent verification of design output in the im)lementation of PC/M 341-192 [ICW Lube Water Piping Removal and CW _ube Water Piping Renovation]. The as-built Dwg. No, JPN-341-192-008 was not
. incorporated in Dwg. No. 8770-G-082, " Flow Diagram Circulating and Intake Cooling Water System," Rev 11. sheet 2 issued May 9, 1995 for PC/M 341-192, This resulted in Dwg. No 8770-G-082 erroneously showing valves I-FCV-21-3A & 3B and associated piping still installed.
- 3. On February 14, 1994, the licensee failed to coordinate a design change with an operational procedure change when PC/M 268-292 [ICW Lube Water Piaing Removal and CW Lube Water Piping Renovation] was completed wit 1out assuring that affected procedure ONOP 2-0030131,
" Plant Annunciator Summary." was revised. This resulted in annunciator E-16. " CIRC WTR PP LUBE WTR SPLY BACKUP IN SERVICE."
incorrectly requiring operators verify the position of valves MV- 4 21-4A & 4B following a SIAS signal using control room indication. These valves no longer received a SIAS signal, were deenergOed and had no control room position indication.
- 4. On October 28,199c, the licensee failed to coordinate a design
& 'ge with an opei6cional procedure change when PC/M 275-290
[Fb-14-6 Low Flow Alarm and " Manual" Annunciator Deletions] was completed without assuring that affected procedure ONOP 2-0030131, i
" Plant Annunciator Summary." was revised. This resulted in i safety-related annunciators LA-12. "ATM STM DUMP MV-08-18A/188 l OVERLOAD /SS ISOL." and LB-12. "ATM STM DUMP MV-08-19A/198 :
OVERLOAD /SS ISOL," incorrectly requiring operators to check i Auto / Manual switch or switches for the MANUAL position. The relay i 1 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE i WITHOUT THE APPROVAL OF THE DIRECTOR, OE !
contacts which energized these annunciators based on switch position were removed to eliminate nuisance alarms.
- 5. On May 12, 1996, the licensee failed to coordinate a design change-with an operational procedure change when Unit 1 fuel offload was commenced without incorporating the prerequisite conditions contained in PC/M 054-196. supplement 0, "St. Lucie Unit 1 Cycle 14 Reload " into OP 1-1600023., " Refueling Sequencing Guidelines."
As a result, requirements for.the operation of two Spent Fuel Pool Cooling Pumps, maximum initial Spent Fuel Pool temperature, minimum time since shutdown, minimum Component Cooling Water system flow to the Spent Fuel Pool heat exchangers. .and operability of control room annunciation were not verifiec prior to the initiation of fuel offload (minimum requirements for operating Spent Fuel Pool pumps and component cooling water flow were not met at the time fuel movement was initiated). PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISC! oSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
w l ESCALATED ENFORCEMENT . ; i PANEL QUESTIONNAIRE INFORMATION REOUIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL t i PREPARED BY: R. Prevatte NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This i information will be used by EICS to 3repare the enforcement letter and Notice. > i as well as the transmitto. memo to t1e Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.) :
- 1. Facility: St. Lucie Unit (s): 1 4
Docket Nos: 50-335 License Nos: DPR-67 ! Inspection Dates: July 30 - Sectember 16. 1995 t Lead Inspector: Richard L. Prevatte
- 2. Check appropriate ooxes:
, [X] A Notice of Violation '(without "boilerplate") which includes the 1 recommended severity level for the violation is enclosed. [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2) 1.C.2.B
- 4. What is the apparent root cause of the violation or problem?
Enaineerina evaluation and orioritization of ootential eouioment oroblem was not timely.
- 5. State the message that should be given to the licensee (and industry) through this enforcement action. j Imorove crioritization and timeliness of resoonse to olant oroblems. l
- 6. Factual information related ;o the following civil penalty escalation or
&i - l
O
- mitigation ~ factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.):
- a. . IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation?-
Was it self-disclosing? Was it identified as a result of a - generic notification?) - Licensee identified anomalous behavior of safety related thermal relief valves on February 20. March 2. and March 10. 1995. but did not take action urtil a failure also occurred on Auaust 10. 1995 and NRC auestionec corrective action. CORRECTIVE ACTION: Although we expect to learn more information b. regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview. See item A. What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term cor. 2ctive action and the timeliness of corrective actions? Initidl problem was under enaineerina review for several months. After auestionina by NRC. the oroblem was thorouahly researched and corrected What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis? Initial - not timely. Final - acod investication and broadened scooe led to review of over 100 relief valves.
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): NCV 94-25-01. Inadecuate desian control of NADH suction relief valves. VIO 94-11-01. "nadeauate corrective action for MOV which stalled durina surveil ~ ance.
. VIO 94-12-01.1E swina bus would not strio on undervoltaae due tq wirina oroblem 94-08-01 Inadeauate corrective action on waterhammer event.
l
~ i l
.i .
Inocerable snubbers ~and SRV PORV tailoices. 94-08-02. Failure to document above non-conformance.~ 94-06-02. Inadeauate desian control on Unit 2 charaina numo seauence. i
,94-06-01. Failure to reoort DG failure.
i Identify the a)plicable SALP category, the rating for. this category and tie.overall rating for the last two SALP periods, as well as any-trend indicated: Ena. Sucoort 1 - 1
- d. PRIOR OPPORTUNITY'TO IDENTIFY: Were there op)ortunities for the
, licensee to discover the violation sooner suc1 as through normal surveillances, audits. QA activities, s notification, or reports by employees? pecific NRC or industry Problem known but not oursued. .
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the
, violation identified during this ins)ection? If there were, identify the number of examples and )riefly describe each one. No. ,
- f. DURATION
- How long did the violation exist?
Problem has existed on thermal relief valves since initial i installation. i i k i 5 l l
M DITIONAL COMMENTS / NOTES:
- 5) Shutdown Cooling Relief Valve Lift A. Background On February 28. while placing the.1A SDC train in service, the licensee experienced a lift of 1A LPSI pump suction relief valve V-3483 (see IR 95-04). The valve did not reseat, and the loss of RCS inventory was abated by closing LPSI hot leg suction. isolation
- valves V-3480 and V-3481, which isolated the valve from RCS pressure. The root cause of the lift was determined to be water hammer, which resulted from passing relatively hot RCS fluid through the suction ,
line at high velocity as the LPSI pump was started. r As corrective action, the licensee revised OP 1-0410022. " Shutdown Cooling." to change the methodology of starting the LPSI pump to the following: e Shut LPSI pump discharge isolation and LPSI
. header isolation valves e Start the LPSI pum) e Immediately open tie LPSI pump isolation valve e Throttle open two LPSI header isolations to 150 gpm per header e Run for 15 minutes e Start the second pump e Throttle open the remaining LPSI header isolation valves to 150 gpm per header e Wait 5 minutes -
e Incrementally open header isolation valves to obtain full flow. The licensee reasoned that this methodology would ' result in a slow increase in flow, allowing controlled ; system heatup and minimizing the potential for water hammer. B. LPSI Discharge Isolation Valve Lift On August 10, while placing the Unit 1 SDC system in service to su] port a cooldown required due to inoperable PORVs (see IR 335/95-16). V-3439, the A LPSI header thermal relief lifted resulting in a loss , of a) proximately 3500-4000 gallons of RCS coolant in the Jnit 1 Pipe tunnel. The following timeline was developed from operator interviews, logs and instrumentation data: 0018 A LPSI pun $p start (ANPS. NWE. Logs) Pressurizer level begins to drop (strip chart
. data)~ .
F
0025 ANPS directs SNP0 to tour pipe tunnel due to 1 minor reduction in pressurizer level (ANPS) No increases in HUT,. RWT, etc noted (ANPS)- SNP0 reports no. unusual conditions in pipe-tunnel.
.0105 B LPSI pump start (ANPS, NWE, Log) l Pressurizer level recovers and oscillates (strip chart) .
0140 Cooldown flow established (ANPS, NWE) 0210 Fire watch calls control room, reports water t issuing from watertight door isolating pipe i tunnel from RAB (ANPS, NWE) ,
- 0215 SDC secured (ANPS, NWE)
Pressurizer level increases and stabilizes (strip chart)
- 0226 Floor drain isolation valves (FCV 25-1 through
- 7) noted to be closed on control panel (ANPS, ,
NWE) . Drain valves subsequently opened (ANPS, NWE) Flooding in RAB ONOP entered (ANPS) Water -levels in pipe tunnel weren't dropping due to clogged floor drains (NWE) 0345 Water in pipe tunnel pumped by maintenance
- personnel to floor drains in RAB (ANPS)
Operators cycle various isolation valves looking - for leak 0611 1A LPSI pump started with NWE observing in pipe tunnel (ANPS) , 0612 NWE identifies V-3439 as passing water (ANPS) The licensee concluded that the cause of the relief valve lift was a pressure surge while LPSI Jumps were .
'o perating in a low-flow condition. The com)ination of RCS pressure (a maximum of 267 psia at the time) and LPSI pump discharge head at essentially no flow (approximately 182 psid) combined with possible perturbations (when starting the pump) was considered enough to challenge the relief valve setpoint (485-515). This condition existed from the time the 1A LPSI pump discharge isolation valve was opened until
> operators initiated flow through the LPSI header
- isolation valves.
V-3439 was designed to provide a 10 percent blowdown, i which, if applied to the lower acceptable lift l setpoint of the valve (485 psig). would require a 48.5 ; psia reduction in pressure to allow reseat. Given I these )arameters, should V-3439 open, RCS pressure would lave to drop to 436.5 asia to allow valve reseat (assuming only a 10 percent ) lowdown). The volume of- i the RCS and pressurizer would preclude such a reseat l until significant volumes of coolant were lost. The volume of coolant lost during the event was i r ,
estimated by the inspector, based upon floor layouts as displayed on drawings. Given water depths reported by the NWE (up to approximately 14" in some areas), the inspector estimated that ap3roximately 3500 gallons were lost. The CVCS nmeup integrator. measuring volume added to the VCT in maintaining pressurizer level on setpoint. indicated that 4000 gallons were added to the VCT. The licensee concluded that the closed floor drain isolation valves. HCV-25-1 through 7 (a set of 7 ganged valves) were the result of valve stroke testing in preparation for Hurricane Erin. During testing conducted by control room operators, some of the valves had failed to stroke properly. As a result, the valves were left closed for troubleshooting and were never reopened. OP 1-0010123. Rev 99. " Administrative Control of Valves. Locks. and Switches." required. in step 8.1.6. that "All valve or switch position deviations or lock openings shall be documented in Appendix C. Valve Switch Deviation Log..." The inspector reviewed archived Appendix C logs completed in July and August and control room open A)pendix C logs and found no evidence that HCV-25-1 t1 rough 7 were logged as being out of position. The failure to enter the valves' closed status into the valve deviation log is an example of a violation (VIO 335/95-15-01. " Failure to Follow Procedures." Example 4). STAR 950917 was initiated to develo for verifying that floor drains were unclogged. p a PM The licensee prepared an evaluation of the effects of the subject setpoint/ blowdown values on plant o)eration. JPN-PSL-SENP-95-101. Rev 1. " Assessment of t1e Effects on Plant Operation of Lifting the LPSI Pump Discharge Header Thermal Relief Valve." concluded that the subject condition would not have a significant effect on safe plant operation during , normal, shutdown and design basis accident conditions. In reaching this conclusion, the evaluation noted the following: e As flowrate through the relief valve (at lift s setpoint pressure) was ap3roximately 40 gpm. the loss of inventory was wit 11n charging system capacity (44 gpm per pump). e During the injection phase of an accident, the LPSI pumps would draw suction from the RWT. thus pressure developed by the pump would not compound a high pressure suction source and the relief valve's lift setpoint would not be challenged.
d e The relief valve in question discharged to a floor drain which directed flow to the safeguards room sump. The sump was designed to be pumped down in level to the EDT automatically when offsite power is available. Thus, with offsite power available, no flooding hazard would exist. Under conditions with no offsite power available. the water level in the safeguards room (after the sump ovecfilled) would not rise to the level of the HPSI pump motors until ap)roximately 7 hours after the lift. Before t11s time elapsed, the licensee reasoned that sump high level alarms would alert operators to the event, allowing operator intervention prior to the loss of the HPSI pump. e The licensee noted that, while SDC was assumed to be ) laced in service during postulated small break .0CAs. ESDEs. and SGTRs (when RCS pressure may have been high enough to have led to a relief valve lift), the FSAR analysis demonstrated that fuel damage (and thus the release of significant amounts of radioactive material to the RCS) was involved only because of extremely conservative assumptions. The evaluation went on to state that "A review of FSAR analysis of small break LOCAs. ESDEs and SGTRs demonstrates that these accidents will not result in fuel damage if assumptions that reflect the actual operating history of the plant are applied. Therefore, the radiological consequences of these FSAR accidents will not be increased and the FSAR offsite doses remain bounding." The inspector took exception to the licensee's conclusion. The subject passage was included in Section 4 of the evaluation. " Analysis of Effects of Lifting V3439." in a section entitled " Increases in Radiological Consecuences of Design Basis Accidents." The inspector founc that, in choosing to neglect design Jasis assumptior.s in their analysis of the event (specifically, a return to power and fuel l failure resulting from the most reactive rod failing l to insert), the licensee did not evaluate the l increases in the radiological consequences of design l basis accidents. Rather, the licensee evaluated the ; radiological consequences of a less significant set of accidents and concluded, without providing ) quantitative results, that the radiological i consequences of design basis accidents bounded the noted relief valve lift. While the inspector agreed with the licensee's position that the circumstances i assumed in design basis accidents were. '
s probablistically, of low likelihood, the inspector pointed out ttiat the assumptions were the approved licensing basis of the plant and, as such, provided riate common ground upon which to evaluate the the event approp's significance. The inspector brought this to the attention of the licensee, who stated that they would consider the issue. At the close of the inspection period, the licensee had not presented a final position on the issue. As a result, this issue will be trscked as an unresolved item (URI.95-15-04.-
" Adequacy of Engineering Evaluation Regarding Unit 1 Loss of Inventory via V-3439").
On August 12, the inspector requested data on approximately 25 relief valves on both units which communicated with the RCS in some way. The requested data included lift and blowdown setpoints, tolerances, relief capacity, and normal .o)erating pressures experienced by the valves. Saortly after requesting
. the information, the licensee informed the inspector that a team had been formed to evaluate all safety-related relief valve data, The team included members from Engineering, Maintenance. Operations, Tech Staff, and Licensing.
The team's review was documented in JPN-SPSL-95-0334, "St. Lucie Units 1 and 2 Design Review of Safety Related Relief Valves " transmitted to the site by letter dated August 30. The inspector found the methodology of the study to be sound, considering worst case combinations of system operating pressures, relief valve setpoint, and blowdown. Relief valves ! were evaluated for their margin to lift and blowdown l margin (the difference between reseat pressure and- 1 normal system operating pressure). The document l ! reported that, of 114 relief valves reviewed 8 valves on Unit 1 and 5 valves on Unit 2 required further , review due to unacceptable margins of lift or blowdown. Corrective Actions were specified for the l i following valves: Unit 1 Valves e V2324, V2325, and V2326 - Charging Pump Discharge Relief Valves - MEP 107-195M was issued to reduce the design superimposed backpressure from 165 psig to 115 psig. I e V2345 - Letdown Relief Valve - PC/M 108-195 I i issued to reduce letdown backpressure to 430 psig and to reduce the valve's blowdown from 25 percent to 15 percent. e V3412 - HPSI 1B Discharge Header Relief Valve -
]
=. . - - .- .. - - . . . . . . - - . . . ,d I
y ; EP 115-95 was issued to increase the design setpoint from 1735 psig to 1750 psig and to reduce blowdown from 25 percent'to 10 percent. e V3417 - HPSI Pump 1A Discharge High Pressure :
. Header Relief Valve -design setpoint increased .
'from 2400 psig to 2485 psig and blowdown reduced from 25 percent to 15 percent.
e V3468 and V3483 - SDC Suction Rel~ef i Valves - STAR 950430 was issued to evaluate new setpoints and blowdown values. Unit 2 Valves ; e V2345 - Letdown Relief Valve - At the close of-the inspection period, an EP was being prepared . to implement actions similar to those implemented on Unit 1 for this valve. e -V3412 - HPSI 2B Discharge High Pressure Header Relief Valve - At the close of the inspection aeriod, an EP was being prepared to reduce ! alowdown from 25 percent to 10 percent. . e V3417 - HPSI Pump 2A Discharge High Pressure . Header Relief Valve - At the close of the : inspection period, an EP was being prepared to ' increase the valve's setaoint from 2400 psig to 2485 psig and to reduce ] lowdown from 25 percent to 10 percent. e V3439 and V3507 - Low Pressure A and B Discharge l Relief Valves - At the close of the inspection ! period, an EP was being prepared to increase the valve's setpoint from 500 psig to 535 psig. As a result of the licensee's investigation, and through discussions with vendors, the licensee determined that some relief valves had been provided with unacceptably high blowdown values. This was, apparently, due to procedural problems at the vendor's test facility. At the close of the inspection period, the vendor (Crosby) was considering the 10 CFR 21 ramifications of the issue. The licensee documented the conditions on STAR 951024. The inspector reviewed the STAR and noted that it had not been identified as an "N" STAR (indicating a nonconforming condition). The inspector brought this to the attention of QC, and the condition was corrected. The licensee identified the affected relief valves and segregated them ' appropriately. The inspector reviewed the licensee's STAR database 1 L. .
s' for' events similar to the subject event and found the following: e STAR 2-950167. initiated February 20, documented the lifting of SDC heat exchanger CCW relief-valve SR-14350 when stroking CCW "N" header isolation valves closed. Once open, the relief valve had to be isolated (by closing an upstream valve in the process line) to bring about a reseat. e STAR 0-950234, initiated March ~2. documented the fact that relief valves had lifted and that blowdown values placed the reseat pressure of the valves-in the operating ranges of the systems they protected. e STAR 1-950269. initiated March 10. documented relief valve lifts on the Unit 1 CVCS letdown line during evolutions which should not have challenged the valve's setpoint, e STAR 0-950917, initiated August 18. documented the subject SDC relief valve lift. In addition to the STARS referenced above. IR 95-05-01 discussed work performed on the Unit 2 CVCS system to prevent letdown line relief valve lifts. The IR also described the failure of the relief valve to reseat (once lifted) due to a blowdown value which placed the reseat pressure below the system's normal operating pressure. The inspector reviewed the status of the STARS listed above and found them all to be open. The inspector discussed the timeliness of the resolutions to the subject STARS with the licensee. The licensee stated that their focus had been on the methodologies for setting blowdown values on the valves in question, rather than on the appropriateness of the setpoints themselves. The licensee offered STAR 950234 as being illustrative of this point. The proposed corrective actions included: o Completion of SRV test benches, which would allow the licensee to better set and test SRVs for. lift set)oint and accumulation. It was noted that t1e bench had only limited blowdown test capability. e Performing an engineering design basis review of all safety related SRVs to validate or correct setpoints and issue a design document that summarizes the design data.
l 4 ~ J
- Enhancing journeyman training on SRVs.
While the inspector found the. licensee's 3roposed activities prudent, it was noted that notling ! precluded engineering from addressing the setpoint ! issue earlier in the process. The licensee stated I that the STAR was addressed in stepwise fashion and that the maintenance-related items were addressed prior to forwarding the STAR-to engineering. , The inspector found that the licensee's corrective I actions for the subject event were comprehensive and sound. However, the inspector concluded that the' actions could have reasonably been expected to be performed in a much more timely fashion. The subject , phenomenon was identified as early as February,1994, : and repeated itself on no less than 3 separate , systems, and on both units, prior to the most recent , event. Once focused on the issue, an engineering- ! 4 product of high quality was developed, and corrective !
. actions initiated, in approximately 2 weeks and i
identified valves requiring attention in a : comprehensive action. 10 CFR 50, Appendix B required ' that, for conditions adverse to quality, prompt corrective action be taken to prevent recurrence. . The licensee's failure to take prompt corrective l action to the February / March events is a violation ! (VIO 335/95-15-02, " Failure'to Take Prompt Corrective i Actions for Repeated Relief Valve Lifts"). I e t l l l
. _ - . _ - , -- - i
s ( Prooosed Violation B 7 10 CFR 50. Appendix B, Criterion XVI, " Corrective Actions," 'recuires, in part, that measures be established to assure that conditions acverse to quality are promptly identified and corrected. Contrary to the above, prompt corrective action was not taken in the case of St. Lucie Action Requests which reported anomalous relief valve behavior and which were initiated on February 20 March 2 and March 10, 1995. The failure to take prompt corrective action for these conditions led to a repetition of the anomalous behavior on August 10. 1995, when Unit 1~ relief valve V-3439 lifted and failed to reseat without operator intervention. The subject event resulted in approximately 4000 gallons of reactor coolant accumulating in the Unit 1 pipe tunnel. This is a Severity Level III violation (Supplement I). f . s k' 1
-. - - - . . - - -. . ~
1 -:l ESCALATED ENFORCEMENT PANEL 00ESTIONNAIRE . INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL-PREPARED BY: DATE PREPARED: May 16.1995 L NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees pridr to an Enforcement Panel. (This information . will be used by EICS to preaare the enforcement letter and Notice, as well as the transmittal memo to the Office of Enforcement explaining and justifying the. Region's proposed escalated enforcement action.) ;
- 1. Facility: St. Lucie '
Unit (s): 1 Docket Nos: 50-335 l 1 License Nos: DPR-67 Inspection Dates: M i Lead Inspector: M -
- 2. NOTES:
A. A draft Notice of Violation, including the recommended severity level for each violation, should be enclosed. The violation (s) in the Notice should be Carefully considered by both the inspector and Section chief, and should be complete regarding the specific requirement to be cited and the appropriate level of specificity as ; to how and when the requirement was violated. l 1 B. Copies of applicable Technical Specifications or license conditions ) cited in the Notice should be enclosed. j
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2)
I.C.3 or I.D.4
- 4. What is the apparent root cause of the violation or problem?
i coonitive oDerator action - failure to inform the facility licensee ; the he had manioulated the wrona valve while Derformina a Drocedure
--This document contains predecisional information--
It can not be disclosed outside NRC without the i
. aproval of _the Regional Adninistrator !
. k l
\7 !
~
~ 5! State the message that should be given to the' licensee (and industry) through.this enforcement action.
g jv is the best oolicy
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2. Appendix C, Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation? Was it self-disclosing? _W as it identified as a result of- a generic notification?)
this was identified by the facilittlic3nsee's investication of the gygr11.s surroundina a temocrary lots of decay heat removal
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
the coerator involved voluntarily terminated his emoloyment with FP&L and his NRC ooerator's license was terminated What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? M
--This' document contains predecisional information--
It can not be disclosed outside NRC without the - approval of the Regional Adninistrator
i V What was the degree of licensee initiative'to address the violation and the adequacy of root cause analysis? the facility licensee was very aaaressive in detenninina the root ! cause of the event. The root cause analysis aooears thorouah. l l l
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): NA Identify the applicable SALP category, the rating for this category and the overall rating for the last two SALP periods, as well as any trend indicated:
. NA __
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities for the licensee to discover the violation sooner such as through normal surveillances. audits. 0A activities, specific NRC or industry notification, or reports by employees?
there were no orior occortunities to identify this
. i
--This document contains predecisional information-- !
It can not be disclosej outside NRC without the approval of the Regional Adninistrator l l
)
1
1 g
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation l identified during this inspection? If there were. identify the number of examples and briefly describe each one.
NA
- f. DURATION: How long did the violation exist?
- g. ADDITIONAL COMMENTS / NOTES:
=E*,--3 5 A$ 4'WAfr% & , tey 1
--This document contains predecisional information--
It can not be disclosed outside NRC without the approval of the Regional Adninistrator I l l I
l <a l o NOTICE OF V!0! ATION Utility Florida Power and Light Docket Nos. 50-335 Unit (s) 1 License Nos.DPR-67 l l During an NRC ins violation (s) of NRC requirements I were identified.pection conducted on In accordance with the " General Statement of Policy and ' Procedure for NRC Enforcement Action,10 CFR Part 2 Appendix C, the violation (s) is listed below: 10 CFR 50.5 Deliberate misconduct requires that any employee of a licensee may not: deliberately submit to a licensee information that the person submitting the information knows to be incomplete or inaccurate in some respect material to the NRC, Contrary to the above, on March 4,1995, a licensed operator, docket number xxxxxx, operated a valve that caused a temporary loss of shutdown cooling at St. Lucie Unit 1, repositioned the valve to restore shutdown cooling, and failed to inform licensee management that his operation of the valve was the cause of the loss of shutdown cooling. This is a Severity Level _III Violation (Supplement I). l I l Pursuant to the provisions of 10 CFR 2.201, Duke Power Company is hereby required I to submit a written statement or explanation to the U. S. Nuclear Regulatory Commission ATTN: Document Control Desk, Washington, DC 20555, wi.th a copy to the . Regional Administrator, Region II, and a copy to the NRC Resident Inspector at the facility within 30 days of the date of the letter transmitting this Notice c' Violation (Notice), This reply should be clearly marked as a " Reply to the Notice of Violation" and should include for each violation: (1) the reason for the violation, or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and the results achieved. (3) the corrective steps that will be taken to avoid further violations, and (4) the date l when full compliance will be achieved. If an adequate reply is not received I within the time specified in this Notice, an order or Demand for Information may be issued as to w1y the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extend the response time. L Dated at Atlanta, Georgia this day of January 1993
4 ESCALATED ENFORCEMENT PANEL.0UESTIONNAIRE 4 INFORMATION REQUIRED TO BE-AVAILABLE FOR EN'FORCEMENT PANEL PREPARED BY: R. Prevatte
' NOTE: The Section Chief is responsible for preparation of this questionnaire
. and its distribution to attendees prior to an Enforcement Panel. (This information will be used by EICS to 3repare the enforcement letter and Notice, as well as the transmittal memo to tie Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit (s): 1
.j Docket Nos: 50-335 License.Nos: DPR-67 Inspection Dates: July 30 - Seotember 16. 1995 Lead Inspector: Richard L. Prevatte
~2. Check appropriate boxes: l A Notice of Violation (without "boilerplate") which includes the l
[X] recommended severity level for the violation is enclosed. j [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2)
I.C.7
- 4. What is the apparent root cause of the violation or problem?
Failure to follow orocedures (multiole examoles - 8)
- 5. State the message that should be given to the licensee (aei industry) through this enforcement action.
Procedures must be used and followed. If errors exist in the orocedures that Drevent follow 1na them. the errors must be corrected. S
t
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2. Appendix C Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation?
Was it self-disclosing? Was it identified as a result of a generic notification?) 4 examoles identified by NRC. 2 examoles by licensee. and 2 were sel f-identi f yina .
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
Some orocedure chanaes made. Dersonnel disciolined. and licensee strivina to imorove standards and oerformance. What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? Promot action taken each event. What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis? This is a lona term action oroblem_
- c. LICENSEE PERFORMANCE: This factor takes into account the last two l ears or the period within the last two inspections, whichever is onger.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): NCV 95-07. Loss SDC - incorrect valve manioulation by ooerator. VIO 94-22-02. Lookeeoina errors. Identify the a)plicable SALP category, the rating for this ! category and tie overall rating for the last two SALP periods, as ! well as any trend indicated: 4 Goerations 1 Recent events indicate neaative trend.
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there op)ortunities for the licensee to discover the violation sooner suc1 as through normal surveillances, audits, 0A activities, s notification, or reports by employees? pecific NRC or industry E1.
l
i
- e. MULTIPLE OCCURRENCES: 'Were there multiple examples of the. :
violation identified during this ins >ection? If there were, identify the number of examples and ariefly describe .each one. , 8 examoles. see attached violations !
- f. DURATION: How long did the violation exist?
Y0 l r l
'l
,i f
v l I j i
3 1 ADDITIONAL. COMMENTS / NOTES: I D l I l i l l i
)
l 1
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i i ESCALATION AND MITIGATION FACTORS (57 FR 5791, February 18, 1992) IDENTIFICATION CORRECTIVE LICENSEE PRIOR MULTIPLE DURATION ACTION PERFORMANCE OPPORTUNITY TO OCCURRENCES IDENTIFY {
+/ SIE +/- 15 +/- im +im +im +1M Licensee Timeliness of Current Licensee should Multiple used for ,
identified (M) corrective violation is an have identified examples of significant ! (To be applied action (M) Isolated violation violation regulatory I even if. (Did IntC have failure that is sooner as a identified message to ; licensee could to intervene to inconsistent result of prior during licensee. (E) have accomplish with licensee's opportunities inspection identified the satisfactory good such as audits (only for SL I, t vlotetton short term or performance (M) (E) II or III , sooner) remedial action violations) (E) > (E)) NRC Identified Promptly Violation is opportunities OTHER CONSIDERATI(Mis (E) developed reflective of evellable to schedute for licensee's poor discover 1. Legal aspects and potential-long ters or declining vlotation such ' litigation risks corrective performance (E) es through action (M) prior 2. 16egligence, careless dise notification . regard, WIll fulness and 1 (E) management involvement , Self- Degree of Prior Esse of earlier 3. Economic, personal or l' disclosing licensee performance and discovery (E) ' corporate sein - (M 25% ff initiative (M) effectiveness . . there was [To develop of previous 4. Any other regulatory frame- 1 initiative to corrective corrective work factors that need to be identify root actions and action for considered: pending action cause) root cause) siellar with regard to Licensing, violations consission meeting, or press conference. Licensee Adequecy of the SALP - Period of time ! j identified as root cause Consider: between 5. What is the intended message a result of analysis for SALP 1 - (M) violation and for the licensee and thef generic the violation SALP 2 - (0) notification industry? notification (M) SALP 3 - (E) received by (M) Licensee (E) .......... NOTES ----- - Comprehensive Prior $1mflarity l corrective enforcement between the action to history violation and i prevent including notification 4 occurrence of escalated and (E) similar ~ non escalated i vlotation (M) enforcement Innodiste Level of corrective management action not review the taken to notification restore safety received (E)
- and comptlance f (E)
! m SAFETY $1GNIFICANCE: In determining the safety significance of a violation in conjunction with the enforcement process, the ovatustion should consider the technical safety significance of the violation as well as the regulatory significance. Consideration should be given to the metter as a whole in light of the circunstances surrounding the violation. There may be cases in which the technical safety 1 significance of the metter is low while the process control fatture(s) may be significent, and, I therefore, the severity level determination should be based more on the process control failure (s) than on the technical safety issue. The following factors should also be considered: 1) Did the violation !. actually or potentially lapact public health and safety? 2) What was the root cause of the violation?
- 3) Is the vlotation an isolated incident or is it indicative of a progrannotic breakdown? 4) Was
;- ; at aware of or involved in the violation? 5) Did the violation involve willfulness?
t i
-. _ , _ ,, _ . _ , - . - - . . ~ . '
9 Prooosed Violation A Technical Specification 6.8.1.a required that written procedures be established, implemented, and maintained ' covering the activ'ities recommended in Appendix A of Regulatory Guide 1.33. Rev 2. February 1978. Appendix A. paragraph 1.d includes administrative procedures for 3rocedural adherence. Procedure 01 5-PR/PSL-1. Rev 62 " Preparation. Revision. Review / Approval of Procedures." Section 5.13.2. stated that all procedures shall be strictly adhered to. Contrary to the above, the following examples of procedural noncompliance were identified:
- 1. OP 1-0030127. Rev 68. " Reactor Plant Cooldown - Hot Standby to Cold Shutdown." required, in part. that operators block Main Steam Isolation System (MSIS) actuation when block permissive annunciations were received. ONOP 1-0030131. Rev 60. " Plant Annunciator Summary." required that, upon valid receipt of annunciators 0-18 and 0-20. operators immediately block MSIS channels A and B respectively.
Contrary to the above, on August 2.1995, during a cooldown of St. Lucie Unit 1. operators failed to establish the required MSIS blocks resulting in A and B channel MSIS actuations.
- 2. OP 1-0120020. Rev 72. " Filling and Venting the RCS." precaution 4.2. required that Reactor Coolant System (RCS) venting, described in the procedure, not be attempted if RCS temperature was above 200 F.
Contrary to the above, on August 2,1995. Reactor Coolant Pump (RCP) seal venting. 3erformed in an attempt to correct seal package leakage in t1e IA2 RCP in accordance with Appendix E of the subject procedure, was performed while RCS temperature was approximately 370 F. As a result, design temperatures of RCP seal components were approached or exceeded.
- 3. OP 1-0120020. Rev 72 " Filling and Venting the RCS." Appendix E.
" Restaging Reactor Coolant Pump Seals." required the use of RCP seal injection while restaging was attempted.
Contrary to the above, on August 2, 1995. restaging of the 1A2 RCP seal package was attempted without seal injection aligned to the seal package. As a result, design temperatures of RCP seal components were approached or exceeded.
- 4. OP 1-0010123. Rev 99. " Administrative Controls of Valves. Locks, and Switches." step 8.1.6, required, in part, that all valve sosition deviations be documented in the Valve Switch Deviation og.
Contrary to the above, on or about August 1. 1995. HCV-25-1 through 7 were repositioned and left in the closed position
f 4 without the required entries being made in the Valve Switch Deviation Log. The valves' positions exacerbated a loss of RCS ' inventory.
- 5. OP 0010129. Rev 24. " Equipment Out-of-Service." step'3.2. required e that all equipment required by Technical Specifications be logged in the Equipment Out-of-Service Log when determined to be inoperable.
Contrary to the above, inspections performed on September 1 and 2. 1995, identified inoserable equipment, required by Technical Specifications, whic1 had not been placed in the Equipment Out-of-Service Log. Specifically. Unit 1 Containment Purge Valve FCV 4 and the 1B Emergency Diesel Generator Fuel Oil Transfer _ Pump were both inoperable without being entered into the Equipment Out-of-Service Log.
- 6. OP 1-0410022 Rev 22. " Shutdown Cooling," step 8.3.7 required that V3652. the B Shutdown Cooling (SDC) hot leg suction isolation valve,- be locked open while placing the B SDC loop in service.
Contrary to the above, on August 29. a control room operator failed to place V3652 in a locked open condition while placing the B SDC loop in service. As a result, the IB Low Pressure Safety Injection Pump was operated with its suction line isolated.
- 7. 01 16-PR/PSL-2, Rev 1. "St. Lucie Action Report (STAR) Program."
required that STARS be initiated for Quality Assurance audit findings and independent technical review recommendations.
. Contrary to the above. a STAR was not generated when a Quality Assurance review of an inadvertent Unit 1 containment spraydown, documented in interoffice corres3ondence J00-95-143. identified the practice of pre-lubricating :CV-07-1A, Containment Spray header A flow control valve, when performing valve stroke time testing.
- 8. ADM-08.02, Rev 7. " Conduct of Maintenance." Ap)endix 5. step 5.
recuired that procedures be present during worc and that incividual steps be initialed once performed. Contrary to the above, inspection of work in progress revealed that individual steps were not initialed upon completion for work conducted in accordance with Plant Change / Modification 11 195. This is a Severity Level III violation (Supplement I). I
O y i ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE i INFORMATION REOUIRED TO BE AVAILABLE FOR ENFORCEMENT PRE-PANEL ,
- PREPARED BY: R. L. Prevatte NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This information will be used by EICS to )repare the enforcement letter and Notice.
-as well as the transmittal memo to t1e Office of En orcement f explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit (s): 1 Docket Nos: 50-355 License Nos: DPR-67 Inspection Dates: Auaust 28 - Sectember 30. 1994 Lead Inspector: R. L. Prevatte l
- 2. Check appropriate boxes:
[X) A . Notice of Violation (without "boilerplate") which includes the
' recomended severity level for the violation is enclosed.
[] This Notice has been reviewed by the Branch Chi" or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [X) Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2) 1.D.3
- 4. What is the apparent root cause of the violation or problem?
The accarent root cause for the event is a failure. on the cart of Ooerations Deoartment manaaement. to orovide control room ooerators with Ar& grate information reaardina the imolications of elianina the 1C ICW pygg to the 1A3 bus. This failure acoears to be the result of a failutg l THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION - IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROWAL OF THE REGIONAL ADMINISTRATOR n.,
l > c h ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE to recoanize the noted limitations as they were described in IR 94-12.
- 5. State the message that should be given to the licensee (and industry) through this enforcement action. .
A thorouah. thouahtful review of conditions adverse to safety must be . conducted followino identification of such conditions.
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation?
Was it self-disclosing? Was it identified as a result of a generic notification?) The violation was identified by the resident insnector durina a control room tour,
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference.
describe preliminary information obtained during the inspection and exit interview. Voon identification of the subject electrical lineuo. the licensee declared the 1A EDG out-of-service. A Niaht Order. correctly describina the imoact of the subject electrical alianment was oromulaated. What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? See above. What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis?
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): e VIO 335.389/94-12-01. Inadeauate Corrective Action for a Previous Vioiation for Inadeauate Surveillance Testina of the C
-THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 2
o ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE ICW Pumo. Reauirement: 10CFR50 ado. B Criterion XVI. Corrective Action Date issued: May 20. 1994 Idpr,tify the a)plicable SALP category, the rating for this category and t1e overall rating for the last two SALP periods, 'as well as any trend indicated: SALP Cateaory: Ooerations The licensee has achieved SALP ratinas of 1 for the last two SALP oeriods. There have been an increasina number of events associated with Ooerations in the cast six months: however. these events have not resulted in the identification of a clear trend.
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there cpaortunities for the licensee to discover the violation sooner suc1 as through normal surveillances, audits, OA activities, specific NRC or industry notification, or reports by employees?
The violation could have been orevented by a more comorehensive resoonse to the findinas of IR 94-12. The vulnerability at the center of the current issue was discussed in that recort. ,
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the
' violation identified.during this ins)ection? If there were, identify the number of examples and 3riefly describe each one. l There were not multiole examoles of this violation identified durina this insoection oeriod.
- f. DURATION: How long did the violation exist?
This violation occurred in an isolated fashion. The actual time. from initiation of the sub.iect electrical lineuo to the identification by the insoector. was aooroximately 3 hours. ADDITIONAL COMMENTS / NOTES: i
- THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTS!DE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 3
ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE NOTICE OF VIOLATION 10 CFR 50, Anendix B, Criterion XVI. Corrective Action, as implemented by approved "L Topical Quality Assurance Report, TOR 16.0 revision 8.
" Corrective Action," required that, for significant conditions adverse to. quality, action shall be taken to preclude repetition.
Contrary to the above, on August 29, 1994,. the licensee was found to be o)erating the 1C Intake Cooling Water Pump powered from the 1AB bus. T1e configuration had been identified in NRC Inspection Report 335.389/94-12 as representing an electrical configuration for which Technical Specification surveillance testing for Emergency Diesel Generator operability had not been satisfied. Specifically. load shed testing of the 1AB bus, while aligned to the 1A3 bus had not been performed as required by Technical Specification 4.8.1.1.2.e.3.a and 4.8.1.1.2.e.5.a. The report also discussed a 35 day period in 1993 when a similar electrical confiouration on Unit 2 resulted in operation without the 2B Emergency Diesel Canerator being demonstrated operable. While the licensee develo)ed a Night Order to alert Unit 1 operators to the limitations of the su] ject electrical lineup the Night Order failed to properly describe the impact of the alignment on the unit. Thus, the licensee's corrective actions failed to prevent the re p rence of establishing electrical plant configurations which failed !o satisfy Technical Specifications. THIS DOCUMENT CONTAINS PREDECISIONAL INFORMAT!ON - PPR A 0F THE R G1 AL INISTRATOR 4
. 4 ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE .
INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMErF PRE-PANEL PREPARED BY: R. L. Prevatte ~ NOTE: The Section Chief is responsible for preparation of this and its distribution to attendees prior to an Enforcement Panel. questionnaire (This information will be used by EICS to 3repare the enforcement letter and Notice, as well as the transmittal. memo to t1e Office of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit (s): 1-Docket Nos: 50-355 License Nos: DPR '
Inspection Dates: Auaust 28 - Seotember 30. 1994 Lead Inspector: R. L. Prevatte
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is enclosed. [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [X] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits- the violation (s) (e.g. . Supplement I.C.2)
VII.D.2
- THIS DOCUMENT CONTAlWS PREDECISIONAL INFORMATION =
PPR AL OF THE REGI AL INISTRA 5
i ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE ~!
- 4. What is the apparent root cause of the violation or problem?
The aooarent root cause(s) for the event are: , e A desire on the cart of the ANPS to chronoloaically tie 1A EDG inocerability to the chance in swino bus oower sucoly lineuo made earlier in the day. This was a conservative decision with resoect to the time allotted in the aoolicable TS AS. e A desire by the licensee to take credit for hourly RC0 control board walkdowns as satisfyino AS (b) of TS 3.8.1.1 and to reoresent such act,1ons as havina occurred within the TS time reauirements. e An aooarent miscommunication between the ANPS and the Ooerations Suoervisor as to how the subiect 100 entries should be made. The miscommunication was most orobably cerceotual on the cart of the ANPS. The ANPS in auestion has had disaareements in the cast with the Ooerations Suoervisor. orior to his accointment as - Ooerations Suoervisor. The insoector witnessed one such disaareement (one cited by the ANPS in his discussion of this event as drivinc his actions) durina a Unit 1 startuo. in which the ANPS refusec to sian off a orocedural sten without first obtainina a Temocrary Chance to correct a misleadina reauirement. The Ooerations Suoervisor (then Assistant Ooerations Suoervisor) insisted that the ANPS sian off the steD. annotatina it with an eXolanation of What oortions of the steo did not aDDiv to the sianoff. This methodoloov of dealina with Drocedural oroblems was not an acceotable method oer olant orocedures and recent manaaenent direction and the ANPS held fast to his oosition. The disaareement arew more intense and the (then) Doerations Suoervisor and 00erations Manaaer were summoned to the control room to resolve the issue. After a short review. tne (then) Ooerations Suoervisor directed that the orocedure in auestion be revised via Temocrary Chance. in accordance with clant Drocedures. The insoeCtor felt at the time that the ANPS had oerformed well in maintainino his oosition and that the (then) Operations Suoervisor had made the correct decision with reaard to the actions reavired to correct the situation. In the current event. the ANPS exolained to the insoector that he cerceived the (now current) Ooerations Suoervisor as directina him to modify the subiect loos. althouah he acknowledaed that no direct-statement to that effect was made. Given his cerceotion. the ANPS stated that he was unwillina to ao throuah another araument with the (current) Doerations Suoervisor. fearina that it ! would. Ultimately, affect his .1ob security.
"THl$ DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 6
1 ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE
- 5. State the message that should be given to the licensee (and industry) through this enforcement action.
Control room loas must orovide a chronoloaically accurate descriotion of the actions cerformed on a oiven shift and must remain inviolate.
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation?
Was it self-disclosing? Was it identified as a result of a generic notification?) The violation was identified by the resident insoector reviewina the licensee's loas followina an EDG ooerability issue.
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
The licensee has counseled the individual resoonsible for the I odification of the subiect loa entries. The Ooerations Ueoartment issued a Nicht Order reinforcina existino orocedure , cuidance reaardina lookeeDina. After beina told. on Seotember 1. ! that the insDector found the ioas unsatisfactory (tnev nad not l been corrected to indicate that the Auaust 29 entry was l' nisleadina) . the licensee made a late loa entry correctina the listorical record. What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? l See above. l What was the degree of licensee initiative to address the l violation and the adequacy of root cause analysis? i The licensee has concurred that the modification was not in l accordance with site colicy. The issue is still emeraina at this l time and has not been fully develooed by the licensee. l
- THIS DOCUMENT CONTAINS PREDEclSIONAL INFORMATION-- i IT CAN NOT BE D!sclosED OUTSIDE NRC WITHOUT THE I APPROVAL OF THE REGIONAL ADMINISTRATOR 7
ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): No recent cases of modification of records have been identified. Identify the a)plicable SALP category the rating for this category and t1e overall rating for the last two SALP periods, as well as any trend indicated: SALP Cateaory: Ooerations The licensee has achieved SALP ratinas of 1 for the last two SALP oeriods . There have been an increasina number of events associated with Goerations in the cast six months: however. these events have not resulted in the identification of a clear trend.
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there op)ortunities for the licensee to. discover the violation sooner suc1 as through normal surveillances, audits. 0A activities, specific NRC or industry notification, or reports by employees?
Licensee manaaement could have. in the course of 100 reviews. identified the violation: however. Knowledae of the timina and oroaression of the 1A EDG ooerability issue would have been a orerecuisite to sach an identification.
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this ins)ection? If there were, identify the number of examples and ariefly describe each one.
There were not multiole examoles of this violation identified durina this insoection oeriod.
- f. DURATION: How long did the violation exist?
This violation occurred in an isolated fashion. The chanaes to the control room 100 were identified aDoroximately 2 days after the occurrence. ADDITIONAL COMMENTS / NOTES:
*TMIS DOCUMENT CONTAINS PREDECISIONAL INFORMAfl0N--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 8
1 ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE i NOTICE OF VIOLATION. Unit 1 TS 6.8.1.a required that written procedures shall be established i and implemented covering the activities recommended in Appendix A of . , Regulatory Guide 1.33 Revision 2. February 1978. Appendix A, paragraph 1.h includes administrative procedures for log keeping. St. Lucie Administrative Procedure 0010120, revision 63, " Conduct of-Operations " A)pendix F. " Log Keeping " stated that-log entries were to be made in a c1ronological order and that, where this was not possible, entries were to be preceded by the words " Late Entry." Contrary to the above, on August 29, 1994, a Unit 1 Assistant Nuclear Plant Supervisor modified and appended Unit 1 control room log entries made on a previous shift. The modifications were not annotated in any way and created a false impression of the activities of the previous shift. I l I a j l l
- THIS DOC 1 MENT CONTAlWS PREDECISIONAL INFORMATION**
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL Of THE REGIONAL ADMINISTRATOR 9
t ESCALATED ENFORCEMENT PANEL OGSTIONNAIRE During a Unit 1 control room tour conducted at approximately 4:00 p.m. August
- 29. the inspector noted that the 1AB 4.16 KV bus was aligned to the 1A3 4.16 KV bus and that the 1C ICW pump was operating in lieu of the 1A ICW pump. The lineup had been made to support maintenance activities in the Unit 1 intake bays. The 2AB bus was normally aligned to the 183 bus and was the source of power for the IC ICW pump. During a postulated LOOP. the 1A3 bus would be' powered by the 1A EDG. The electrical lineup in question was effected at 1:26 p.m. on August 29.
As documented in IR 94-12. the IC ICW aum) had never been tested for load shedding capabilities when powered wit 1 tie 1AB bus aligned to the 1A3 bus. As a result, TS surveillance 4.8.1.1.2.e.3 a and 4.8.1.1.2.e.5.a. which verified load shedding capabilities in response to LOOP and LOOP /SIAS signals, had never been satisfied. As these surveillance tests formed part of the bases for 1A EDG operability. the operability requirement of TS LCO 3.8.1.1 was not satisfied when the 1AB bus was aligned to the 1A3 bus with the 1C ICW pump operating. During a postulated DBA involving a loss of offsite power, the IC4 pumps were designed to load shed from their respective busses and sequence back onto the busses in 9 seconds. The design feature was provided to prevent EDG overload conditions during reenergization of 1E busses. A failure of an ICW pump to load shed would have the effect of moving the pump from the 9 second to the 0 second EDG load block, increasing the EDGs starting load. The inspector questioned the ANPS as to the operability of the 1A EDG, given that the 1AB bus was aligned to the 1A3 bus. The ANPS stated that he was aware that the electrical lineup in question resulted in 1C ICW pump inoperability and that the pump had been declared inoperable accordingly. The ANPS stated that the basis for his determination was a Night Order which stated that the pumps powered from the 1AB bus could not be taken credit for , when aligned to the 1A3 bus. A caution tag had been hung on a 1A3-to-1AB breaker handswitch to that affect. The inspector raised his concern regarding EDG operability to Operations Department management. After discussions with , engineering and other plant personnel. Operations management directed that the l 1A EDG be declared inoperable based upon the noted failure to perform required surveillance testing. The 1A EDG was declared inoperable at approximately 5:00 p.m., however the licensee chose to establish the time of inoperability at 1:26 p.m.. the time the noted electrical lineup was established. In response to this issue, the licensee performed an evaluation of 1A EDG I performance for the subject electrical lineup. As the load shedding l capabilities of the 1C ICW pum) had never been tested, the analysis assumed l that the Jump would not load sled. effectively moving the Jump to the 0 second l load bloc ( of the 1A EDG. The licensee found that the comaination of the 1A HPSI pump (400 HP) and the 1C ICW aump (600 HP) alone was enough to exceed the motor starting capability of the EE described by Figure 3 of the EDG system DBD as approximately 980 HP.
-THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION
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? ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE The inspector concluded that, in a Night Order dated May 3, 1994. the licensee failed to accurately convey to operators the findings of IR 94-12. Paragraph 4.d. which stated in part:
"On Unit 1. the swing pumps have been normally aligned to the B-train safety bus. . .The inspector. . .found that the same failure to adecuately test load shed capability existed; however, the failure involvec not testing the 1C ICW and CCW pumps when powered from the Unit 1 A-train safety bus.
[The failure to properly test the load shedding characteristics of the Unit 2 swing pumps]. . .resulted in the 2B EDG not being demonstrated operable for the periods in which the C ICW pump was aligned to the B-train safety bus..." In response to this issue, the licensee generated a new Night Order which correctly described the impact of aligning operating 1AB bus pumps to the 1A3 bus. The failure to adequately convey operational limitations to control room operators resulted in a recurrence of operating a Unit's electrical plant in a configuration for which EDG operability had not been demonstrated. The licensee's failure to prevent this recurrence is a violation (335/94-20-01). At approximately 11:00 a.m. on August 31. the inspector reviewed the Unit 1 control room log and found the following: 1 e An entry, made at 1:26 p.m. on August 29. described the change in l the electric plant described above. At the end of the description, the entry stated " . 1A EDG 005." e An entry, timed at 2:26 p.m. on August 29. stated "1C AFW Pump operable, offsite power available, redundant 'B' components operable." i As the 1A EDG was declared inoperable at approximately 5:00 p.m. as a result of the inspectors observations, the inspector questioned control room o]erators about the log entries (the operators questioned had been on watch w1en the electrical lineup was changed on August 29). The operators had no knowledge of the log entries detailed above. The inspectors discussed the issue with the Operations Supervisor, who stated that the entries were most 3robably made by the peak shift ANPS on August 29 to reflect the fact that the EDG was declared inoperable. The Operations Supervisor also stated: e The time of EDG inoperability had been declared to be the time when the 1AB bus was aligned to the 1A3 bus (1:26 p.m. on August 29). e The entry describing the availability of offsite power supplies and the operability the IC AFW pump and B side ECCS components had
-THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 11
i t ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE been made to satisfy AS (b) of TS LC0 3.8.1.1 which required such checks when an EDG was declared inoperable. The entry was said to i take credit for normal control room walkdowns and log entries in I the RCO. contro.1 room and out-of-service logs. l e The method of log entries in this case was not in accordance with I site procedures. ; The ins)ector discussed the matter with the ANPS who had been on duty during the peat shift on August 29. The ANPS stated that he did make the log entries in question and that the entries were the result of a discussion with the Operations Supervisor, who had directed the ANPS to make log entries describing inoperability of the 1A EDG. The ANPS stated that his understanding of the Operations Su)ervisor's directions was that the logs from th; doy shift of AugJst 29 should )e augmented to include the EDG inoperability. The ANPS stated that in the course of the discussion, he informed the Operations Supervisor that, if inoperability was taken from 1:26
).m., then the one hour period for com)letion of AS (b) of TS LCO 3.8.1.1 had 3een exceeded. The ANPS stated that tie Operations Supervisor directed that RCO board walkdowns and various control room logs be taken credit for as satisfying the AS, a practice which had been used in the past under similar circumstances. Finally, the ANPS stated that he had made the noted log entries with hesitation, but believing that the actions were made under the direction of the Operations Supervisor.
The Operations Supervisor acknowledged the discussion, stating that he had directed the ANPS to declare the 1A EDG inoperable effective at 1:26 p.m. on August 29. The Operations Supervisor stated that it was not his intent that the previous shift's logs be altered and that an apparent miscommunication had existed between himself and the ANPS. The inspector reviewed the Bases for TS LC0 3.8.1.1 which, with regard to the verification of offsite power and component operability required in AS (b) of the LCO stated:
"The term verify as used in this context means to administratively check by examining logs or other information to determine if certain components are out-of-service for maintenance or other reasons. It does not mean to perform the surveillance requirements needed to demonstrate the OPERABILITY of the component."
Consequently, the inspector found that the methodology employed for making the 2:26 p.m. log entry of August 29 was in keeping with the TS. However, the inspector found that the time logged for the activity was misleading both in the statement of when the activity occurred and by whom the activity was performed. 1 i
"THIS DOCUMENT CONTAINS PREDECISIONAL INFCRMATION-- j IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE 4 APP rial CF THE REGIONAL ADMINISTRATOR 12 )
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1 1 i ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE Therefore, the inspector concluded that : e The wrtion of the August 29 1:26 p.m. log entry stating that the 1A E E was DOS. was misleading in that the EDG was declared 00S at approximately 5:00 p.m. that day. Further, the entry did not reflect the activities of the day shift operators. e The August 29 log entry of 2:26 p.m.. stating that offsite power sources were available and that the 1C AFW pump and redundant B side components were operable, was misleading in that the subject verifications were not performed on that shift. In response to this event, the licensee issued a Night Order on August 31 reiterating procedural requirements for maintaining logs chronologically. The inspector reviewed Administrative Procedure 0010120. Revision 63. " Conduct of Operations." and found that Appendix F covered log keeping. Section 2 of the appendix stated, in part. "... entries are to be made in chronological ; order. Where this is NOT possible, entries shall be preceded by the words late Entry." The ANPS's actions, relative to the modification of the logs of , the previous shift were counter to the requirements in the procedure and, as such, constitute a violation (VIO 335/94-20-02). l I I i l I 1
**THIS DOCUMENT CONTAthS PREDECISIONAL INFORMATION
- IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 13 l
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.- .- - . - . -- - - - . . ~. . .- . _.
4 t ESCALATION AND MIT!GATION FACTORS (57 FR 5791, February 18, 1992) 4 IDENTIFICATION CORRECTIVE LICENSEE PRIOR MJLTIPLE DURATION ACTION PERFORMANCE OPPORTUNITY TO OCCURRENCES
- IDENTIFY
+/ SIE +/- M +/- t m + 1015 +im + 1015
- Licensee Timeliness of Current Licensee should Multiple Used for identified (M) corrective violation is an have identified examples of significant (To be applied action (M) footsted violation violation regulatory a
even if (Did 4HtC have fatture that is sooner as a identified message to licensee could to intervene to inconstatent result of prior during licensee. (E) have accomplish with licensee's opportunities inspection identified the satisfactory good such as audits (only for SL 1, violation short term or performance (M) (E) !! or 111 sooner) remedial action vlotations) (E) , (E)) NRC identified Promptly Violation is Opportunities OTHER CollSIDERATIONS (E) developed reflective of available to . schedule for Licensee's poor discover 1. Legal aspects and potential or declining tone term vlotation such titigation risks corrective performance (E) as through . .. I action (M) prior 2./ Negligence, careless dis-notification regard, willfulness and i (E) management involvenartt } Self- Degree of Prior Esse of earlier 3. Economic, personst'or-j disclosing Licensee performance and discovery (E) corporate gain
- (M 25% If initiative.(M) effectiveness there was (To develop of previous 4 ~. Any other regulatory frame-initiative to corrective corrective -work factors that need to be
!- Identify root actions and action for considered: pending action
- cause) root cause) similar with regard to ticonsing, violations conuission meeting, or press conference.
Licensee Adequacy of the SALP - Period of time identified as root cause Considers between 5.-What is the intended messege a result of analysis for SALP 1 - (M) violation and for the licensee and the generic the violation SALP 2 - (0) notification industry?- notification (M) SALP 3 - (E) received by Licensee (E)
; (u) ...o....- NOTES"- ~ ~ ~-
Ccaprehensive Prior $1milarity ' 4 corrective enforcement between the ' 3 action to history violation and prevent including notification < occurrence of escalated and (E) , similar non-escalated - vlotation (M) enforcement d lanediate Level of
'f corrective management action not review the taken to notification restore safety received (E) and compliance (E) mmm SAFETY SIGNIFICANCE: In determining the safety significance of a violation in conjunction with the ,
enforcement process, the evaluation should consider the technical safety significance of the violation as well as the regulatory significance. Consideration should be given to the matter as a whole in light of the circunstances surromding the violation. There may be cases in which the technical safety ! significance of the matter is low white the process control fatture(s) may be significant, and, therefore, the severity level determination should be based more on the process control falture(s) than on the technical safety issue. The following factors should also be considered: 1) Old the violation j actually or potentially impact public health and safety? 2) What was the root cause of the violation?
- 3) is the vlotation an isolated incident or is it indicative of a programmatic breakdown? 4) Was ,
t aware of or involved in the vlotationt 5) Did the violation involve willfulness? r.e . - l l
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j e a ESCALATED ~ ENFORCEMENT
. PANEL QUESTIONNAIRE INFORMATION REQUIpun TO BE AVAILABLE FOR ENFORCE lGNT PANEL PREPARED BY: Mark S. Miller- ,
NOTE: . The Section Chief is responsible for preparation of this 1 questionnaire and its distribution to attendees prior to an l Enforcement Panel. (This information'will be used by EICS to l' prepare the enforcement letter and Notice, as well as the transmittal memo- to the Office of Enforcement explaining and
. justifying the Region's proposed escalated enforcement -action.)
- 1. Facility: St. Lucie Nuclear Plant ;
Unit (B) : 1 l Docket Nos: 50-335- ! License'Nos: DPR-67 i ^ Inspection Dates: Decomher 4-312 1994 : Lead Inspector: Richard L'. Prevatte
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate*') which
. includes the recommended severity level for the violation is enclosed. ,
- l. []
This Notice 'has been reviewed by the Branch Chief or \ Division Director and each violation includes the appropriate level of specificity as to how and when the I requirement was violated. [] Copies of applicable Technical Specifications or license ! conditions cited in the Notice are enclosed. 1
- 3. Identify the reference - to the Enforcement Policy !
Supplement (s) that best fits the violation (s) (e. g. , supplement I.C.2) 'l Suncl emen t'~ I . D. 3 ;
- TMll DOCUMENT CONTAINS PREDECISI ONAL INFORMATION--
.IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE
' APPROVAL OF THE REGIONAL ADMINISTRATOR' ;
I a 4 -- .. # ,m -v- .-.-- #E-, c,-_. .~m. ., _ .y . . ~ , , . - , ' , ..,,.v. , _ _, .r.----
ESCALATED ENFORCDfENT PANEL OUESTIONNAIRE
- 4. What is the apparent root cause of the violation or problem?
Inadecuate analvsis of the desian of the NaOH addition lines to the Uni t 1 Containment Soray System.
- 5. State the message that should be given to the licensee (and industry) through this snforcement action.
Desian reviews must be sufficiently thorouch to orevent the possibility of violatina desian basis assumotions.
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2. ) :
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation? Was it self-disclosing?
Was it identified as a result of a generic notifica tion ?) The errant desiun condition was self-disclosina when it led to the liEtina of a containment sorav suction relief valve durina MOV testina with only 1 CS pumo operat.ina. Operators were alerted to the condition by standina water. The desian feature in anestion involved a common line which effectively cross-connected the NaOH eductors. allowina the discharae from one CS oumo to oressurize the suction of the other CS pump unless the second pumo was ooera tina.
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
The licensee performea a series of interim and final corrective actions. They included: e Validatina conclusions reached as to the reason for the relief valve lif tina by alia}}