ML17229A690
| ML17229A690 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 04/17/1998 |
| From: | Gleaves W NRC (Affiliation Not Assigned) |
| To: | Plunkett T FLORIDA POWER & LIGHT CO. |
| References | |
| IEB-96-002, IEB-96-2, TAC-M95644, TAC-M95645, NUDOCS 9804210428 | |
| Download: ML17229A690 (65) | |
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0 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON> D.C. 2055&4001 April 17, 1998 Mr. T. F. Plunkett President - Nuclear Division Florida Power and Light Company P.O. Box 14000 Juno Beach, Florida 33408-0420
SUBJECT:
COMPLETION OF LICENSING ACTION FOR NRC BULLETIN96-02, "MOVEMENTOF HEAVY LOADS OVER SPENT FUEL, OVER FUEL IN THE REACTOR CORE, OR OVER SAFETY-RELATED EQUIPMENT," DATED APRIL 11, 1996, FOR ST. LUCIE UNITS 1 AND 2 (TAC NOS. M95644, M95645)
Dear Mr. Plunkett:
On April 11, 1996, the U.S. Nuclear Regulatory Commission (NRC) issued NRC Bulletin (NRCB) 96-02, "Movement of Heavy Loads Over Spent Fuel, Over Fuel in the Reactor Core, or Ovei Safety-Related Equipment," to all holders of operating licenses, The NRC issued NRCB 96-02 for three principal reasons:
1.
Alert addressees to the importance of complying with existing regulatory guidelines associated with the control and handling of heavy loads at nuclear power plants, 2.
Request that all addressees review their plans and capabilities for handling heavy loads in accordance with existing regulatory guidelines and within their licensing basis as previously analyzed in the final safety analysis report, and 3.
Require addressees to report to the NRC whether and to what extent they have complied with the actions requested in this bulletin.
Also the bulletin requested that Florida Power and Light determine whether current activities were within the licensing basis and to submit a license amendment request as necessary.
In response to NRCB 96-02, you provided a letter dated May 10, 1996, for St. Lucie Units 1 and 2. This submittal provided both the information requested and the responses required by NRCB 96-02.
NRC staff review of the responses to NRCB 96-02 finds that, overall, the responses are acceptable; therefore, TAC Nos. M95644 and M95645 are closed.
9804210428 9804i7 PDR ADQCK 05000335 8
T.
F. Plunkett PprH 17, 1998 The NRC will continue to review the issue of heavy loads through an ongoing Task Action Plan for heavy loads.
Any additional information required for the completion of the Task Action Plan will be obtained on a plant-specific basis.
If you have any questions regarding this matter, please contact Mr. William Gleaves at (301) 41 5-1479.
Sincerely,
/s/
William C. Gleaves, Project Manager Project Directorate II-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Docket Nos. 50-335, 50-389
Enclosure:
Summary cc w/encl:
See next page DISTRIBUTION:
~ Docket File PUBLIC PDII-3 Reading File J. Zwolinski F. Hebdon W. Gleaves B. Clayton DRP R. Schin OGC P. Ray ACRS B. Thomas To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE PM:PDII-3 LA:PDII-3 P 9:P II aves:c~
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F. Plunkett April 17, 1998 The NRC will continue to review the issue of heavy loads through an ongoing Task Action Plan for heavy loads.
Any additional information required for the completion of the Task Action Plan will be obtained on a plant-specific basis.
If you have any questions regarding this matter, please contact Mr. William Gleaves at (301) 415-1479.
Sincerely, M~ C.
William C. Gle es, Prolect Manager Project Directorate II-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Docket Nos. 50-335, 50-389
Enclosure:
Summary cc w/encl:
See next page
Mr. T. F. Plunkett Florida Power and Light Company ST. LUCIE PLANT CC:
Senior Resident Inspector St. Lucie Plant U.S. Nuclear Regulatory Commission 7585 S. Hwy A1A Jensen Beach, Florida 34957 Joe Myers, Director Division of Emergency Preparedness Department of Community Affairs 2740 Centerview Drive Tallahassee, Florida 32399-2100 M. S. Ross, Attorney Florida Power 8 Light Company P.O. Box 14000 Juno Beach, FL 33408-0420 John T. Butler, Esquire Steel, Hector and Davis 4000 Southeast Financial Center Miami, Florida 33131-2398 Mr. Douglas Anderson County Administrator St. Lucie County 2300 Virginia Avenue Fort Pierce, Florida 34982 Mr. BillPassetti Office of Radiation Control Department of Health and Rehabilitative Services 1317 Winewood Blvd.
Tallahassee, Florida 32399-0700 Regional Administrator Region II U.S. Nuclear Regulatory Commission 61 Forsyth Street, SW., Suite 23T85 Atlanta, GA 30303-3415 H. N. Paduano, Manager
- Licensing & Special Programs-Florida Power and Light Company P.O. Box 14000 Juno Beach, Florida 33408-0420 J. A. Stall, Site Vice President St. Lucie Nuclear Plant 6351 South Ocean Drive Jensen Beach, Florida 34957 Mr. J. Scarola Plant General Manager St. Lucie Nuclear Plant 6351 South Ocean Drive Jensen Beach, Florida 34957 Mr. Kerry Landis U.S. Nuclear Regulatory Commission 61 Forsyth Street, SW., Suite 23T85 Atlanta, GA 30303-3415 E. J. Weinkam Licensing Manager St. Lucie Nuclear Plant 6351 South Ocean Drive Jensen Beach, Florida 34957
I
M YO T F'V W E
P S
N n oductio The following summarizes the results of the U.S. Nuclear Regulatory Commission (NRC) staff's review of licensees'esponses to NRC Bulletin (NRCB) 96-02, "Movement of Heavy Loads Over Spent Fuel, Over Fuel in the Reactor Core, or Over Safety-Related Equipment,"
dated April 11, 1996, and its associated Requests for Additional Information (RAI). The bulletin reminded licensees'of their responsibilities for ensuring that heavy load-handling" operations are performed safely.
It also requested that licensees review their plans and capabilities for handling heavy loads, and ensure that their load-handling operations are in accordance with existing regulatory guidelines and the plant's licensing basis.
Also requested was that licensees identify and present schedules for licensing actions needed to support implementation of their heavy load-handling operations involving spent fuel dry storage casks.
The licensees also were to provide schedules for moving dry storage casks.
The RAI requested that selected licensees evaluate the hazards associated with an in-plant tip-over of spent fuel dry storage casks that could dislodge the cask lid and spent fuel elements.
This summary closes the staff's review of licensee responses to both the bulletin and the associated RAI. Future issues regarding the handling of heavy loads will be addressed generically under the Heavy Loads and Crane Issues Task Action Plan (TAP) and on a plant-specific basis as needed.
Plant-specific reviews needed in the future may require the staff to obtain additional information from individual licensees.
~B~ro~ud NRCB 96-02 was issued as an urgent generic communication that requested licensees'esponses to the following:
(1)
For licensees planning to carry out activities involving the handling of heavy loads over spent fuel, fuel in the reactor core, or safety-related equipment'within the next 2 years from the date of the bulletin, provide the following: A report within 30 days of the date of the bulletin that addresses the licensee's review of its plans and capabilities to handle heavy loads while the reactor is at power (in all modes other than cold shutdown, refueling, and defueled) in accordance with existing regulatory guidelines.
State whether the activities are within the licensing basis and, if necessary, submit a schedule for requesting a license amendment.
Additionally, indicate whether changes to Technical Specifications (TSs) are required.
(2)
For licensees planning to perform activities involving the handling of heavy loads over spent fuel, over fuel in the reactor core, or over safety-related equipment while ENCLOSURE the reactor is at power (in a(l modes other than cold shutdown, refueling, and defueled) that involve a potential load drop accident that was not previously evaluated in the Final Safety Analysis Report (FSAR), submit a license amendment request 6-9 months in advance of the planned movement of the loads to give the staff sufficient time to perform an appropriate review.
(3)
For licensees planning to move dry storage casks over spent fuel, over fuel in the reactor core, or over safety-related equipment while the reactor is at power (in all modes other than cold shutdown, refueling, and defueled) include, in item 2 above, a statement of the capability of performing the actions necessary for a safe plant
~ shutdown in the presence of a radiological source term that may result. from.a breach of the dry storage cask, damage to the fuel, or damage to safety-related equipment due to a load drop inside the facility.
(4)
For licensees planning to perform activities involving the handling of heavy loads over spent fuel, over fuel in the reactor core, or over safety-related equipment while the reactor is at power (in all modes other than cold shutdown, refueling, and defueled), determine whether changes to the TSs will be required to allow the handling of heavy loads (e.g., the dry storage canister shield plug) over fuel assemblies in the spent fuel pool and submit the appropriate information 6-9 months in advance of the planned movement of the loads for NRC review and approval.
Q Is c~upjJQQ The levels of detail in the licensees'esponses to NRCB 96-02 varied significantly.
Although some licensees presented detailed information about their heavy load-handling operations, some licensees (Catawba, Crystal River, Farley, Indian Point 2, Salem, St. Lucie, Summer, Dresden, Fitzpatrick, Hope Creek, LaSalle, Quad Cities, and WNP-2),
either omitted information pertinent to the staff's review in their submittal or referenced previous submittals associated. with NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants."
However, all of the licensees responded to the bulletin.
In response to the bulletin, all the licensees reviewed their plans and capabilities to handle heavy loads and indicated that their plans and capabilities are adequate.
Some discussions about licensees'lans and capabilities to move heavy loads addressed the plant mode of operation (at power or during shutdowns), the type of crane used (non-single-failure-proof, single-failure-proof, or upgraded cranes), and the methods and procedures for implementing the guidelines in NUREG-0612, Phase I. Allthe licensees indicated that their load-handling operations are in accordance with the guidelines in NUREG-0612, Phase I.
The bulletin requested that licensees determine whether their load-handling operations are within the licensing basis of the plant.
Some licensees stated that their operations are within the licensing basis; other licensees committed to evaluate their licensing basis.
Some licensees identified issues to be addressed with the NRC through licensing actions (amendment requests or 10 CFR 50.59 evaluations), and projected schedules for submitting the actions for NRC review.
Following the responses to the bulletin, a few
I licensing actions have been reviewed and approved by the NRC concerning the bulletin.
The issues involve proposed changes to TSs, scope changes to accident analyses, changes in loads and load paths, and updates to UFSAR requirements.
The bulletin also asked licensees to determine if their mov'ement of heavy loads involves potential load drop accidents that were not evaluated previously in the FSAR and, if needed, submit a license amendment request.
Most licensees stated that they move only analyzed loads.
Some licensees indicated that they performed load drop or consequence analyses or both though the guidance in Generic Letter (GL) 85-11 canceled the need to perform any analyses.
Some licensees committed to evaluate the heavy loads identified previously when they 'respon'ded'to NUREG-'0612.
Despite tlie analyses performed, all the licensees stated that they satisfy the recommended guidelines in Section 5.1.1 of NUREG-0612.
Licensees moving heavy loads at power and using load drops and consequence analyses indicated that they have adequate capabilities to safely shut down the plant if a heavy load drop occurs causing a release of radiation or damage to safety-related equipment.
The bulletin also requested that licensees identify plans and schedules for moving spent fuel dry storage casks.
Some licensees stated that they planned to move casks in the near future; other licensees indicated that they had not yet considered onsite dry cask storage.
Based on requests in the bulletin, the staff reviewed the licensee responses to identify:
(1) plant mode during the handling of heavy loads (at power or during plant shutdowns);
(2) type of crane used to liftheavy loads; (3) evaluation of the licensing basis for handling heavy loads, including planned licensing actions associated with heavy loads (i.e., license amendment requests);
(4) plans and schedules for moving heavy loads (particularly spent fuel dry storage and transportation casks); and (5) the type of analysis performed (load drop analysis or consequence analysis or both). Although the bulletin did not specifically request this information, the staff believes that this type of information covers the areas of concern about the licensees'eavy load-handling operations.
On the basis of its review, the staff noted the following points.
D n
d-I a'
Review of the responses to the bulletin revealed that approximately 38 percent of the plants (21'ressurized-water reactors (PWRs) and 20 boiling-water reactors
~ (BWRs)) plan to move'heavy loads at power.
Some of these plants indicated that they move analyzed heavy loads at power and unanalyzed heavy loads during plant shutdowns.
These plants also indicated that heavy load movements over safety-related equipment are minimized to the extent practicable, and their procedures do not allow movements of heavy loads over fuel or over the reactor core in accordance with,"AUREG-0612. Some PWR licensees (i.e., Callaway, Shearon Harris, and Calvert Cliffs) indicated that their heavy load movements involve casks moved within a separate fuel building. As indicated by the licensees, the movement of casks in PWRs that have a separate fuel building involves little or no
4-cask travel over systems needed for safe shutdown functions.
As a result, a dropped cask would not cause significant damage to safe shutdown equipment and, therefore, would have negligible effect on the licensees'bility to shut down the plant safely.
Approximately 39 percent of the plants (28 PWRs and 15 BWRs) indicated that they move heavy loads at plant shutdowns, and about 23 percent of the plants (23 PWRs and 2 BWRs) did not clearly indicate the plant status when heavy loads are moved.
A few of these licensees (e.g., Oyster Creek) that plan to move heavy loads during plant shutdowns also indicated that they plan to perform dry runs at
.,power, before initially-loading the cask..
The staff finds that although some licensees have committed to move only analyzed loads at power, they may not adequately consider the adverse safety consequences of a load drop during the movement of heavy loads.
Some licensees'nalyses consider methods that may be used to preclude a load drop (e.g., enhancements to the load handling system, including upgrades to brakes, instrumentation, and controls, and the use of energy-absorbing structures throughout the load path).
However, they may not consider the adequacy of their capabilities needed to mitigate or manage the adverse consequences of a load drop.
Some examples of such capabilities are the abilities to shut down the plant safely, continue normal operation, maintain personnel access to various areas in the plant, and mitigate potential accidents that could expose individuals to releases.
The staff is also concerned that some licensees may not adequately address the potential consequences of a load drop during practice runs of cask movements while the reactor is at power.
A drop of an empty cask during practice movements could result in similar adverse consequences to the operation of the plant as does the actual movement of a fully loaded spent fuel cask.
Therefore, it is the staff's view that activities involving actual heavy load movements or practice runs of moving spent fuel dry storage casks are to be evaluated by the licensee for potential accidents and consequences.
In addition, the staff is concerned with BWR licensees that move heavy loads while the reactor is at power because, in general, the safety-related systems required for safe shutdowns are susceptible to damage from a dropped heavy load.
These licensees should exhaust all options of establishing safe load paths to minimize the risk of affecting safe shutdown equipment in the event a heavy load is dropped.
e C
U In the responses to the bulletin, approximately 27 percent of the plants (6 PWRs and 23 BWRs) indicated that they use single-failure-proof cranes to liftheavy loads; 14 percent of the plants (12 PWRs and 3 BWRs) indicated that they have upgraded the reliability of their load-handling system in accordance with NUREG-0612, Section 5.1:6 (see explanation below); and about 8 percent of the plants (5 PWRs
and 4 BWRs) indicated that their crane is non-single-failure-proof.
However, almost half the plants (49 PWRs and 7 BWRs) did not clearly indicate the type of crane they use.
NUREG-0612, Section 5.1.6, "Single Failure Handling System," provides the alternative of upgrading an existing crane in lieu of complying with certain recommendations of NUREG-0554, "Single Failure Proof Cranes for Nuclear Power Plants," to achieve improved reliability in toad-handling systems.
Accordingly, several licensees have upgraded their overhead load-handling crane to single-failure-proof status,'or they have improved reliability by increasing the factors of safety or by providing redundancy in certain active components of the cranes..A few-licensees (i.e., Oyster Creek, Dresden, Yankee Rowe) have indicated that they are considering upgrading their cranes or installing new cranes to achieve single-failure-proof capability.
Licensee information regarding the types of overhead cranes used at the plants indicates that many plants have either single-failure-proof cranes in accordance with NUREG-0554, "Single-Failure-Proof Cranes for Nuclear Power Plants," or cranes upgraded in accordance with guidelines in NUREG-0612 (Section 5 ~ 1.6, and Appendix C, "Modification of Existing Cranes)."
Although several plants were not clear about the type of crane they possess, none of the plants indicated that they have cranes and lifting systems that were inadequately designed, installed, and tested.
The staff concludes that many licensees previously performed adequate evaluations of their crane design for lifting heavy loads and the evaluations were accepted by the'taff.
However, the staff is concerned that some facilities could have weaknesses in their load-handling operations.
These weaknesses may include insufficient training of personnel involved in the lifting and rigging procedures, procedures lacking in requirements for evaluating loads and ensuring that the design limitations of the hoisting system are not exceeded, insufficient inspection and preventive maintenance of cranes and lifting devices, and inadequate review of loading capacities.
The staff's view is that the potential exists for any of these weaknesses to result in a single failure involving heavy loads being dropped and causing adverse consequences.
As a result, future staff reviews will be focused on licensees'valuations of their cranes and lifting devices, and related methods and procedures used for complying with the requirements of NUREG-0612.
(3) v l
n 'n I'
Review of the responses to the bulletin indicated that all of the licensees believe that their heavy load-handling operations are in accordance with the licensing basis of the facility. Approximately 24 percent nf the plants (10 BWRs and 16 PWRs) did not address the licensing basis in their responses.
The staff is concerned that some plants that believe their load-handling operation is within the plant's licensing basis may, in fact, be outside the licensing basis.
For example, the staff's reviews of Oyster Creek's (OC's) load-handling operations determined that OC would have operated beyond its licensing basis.
This is because OC was planning to move loads that exceeded the size of the loads previously evaluated in the FSAR.
Approximately 10 percent of the licensees indicated that they will review and modify their licensing basis as needed.
As indicated in the submittals, licensees'reviews of the licensing basis resulted in one or more of the following:
~
identification and analysis of new heavy loads beyond the loads previously
'ddressed in the licensing basis,
~
~ commitments to only move heavy loads that were previously analyzed;
~
determinations that heavy load-handling operations deviated from previous commitments and the licensing bases, and
~
determinations that change the TSs are needed.
Licensees'eviews of their plans and capabilities to handle and control heavy loads have resulted in some licensees undertaking licensing actions to implement their load-handling operations.
The following are examples of planned licensing actions noted in the responses to NRCB 96-02:
I e
i Brunswick:
License amendment request to make the FSAR consistent with actual plant operations (completed).
Fitzpatrick:
Changes to the TSs to allow the movement of spent fuel dry storage casks at power (schedule TBD).
Nine Mile Point:
Design change involving reracking of the spent fuel pool (schedule TBD).
North Anna:
Various license amendments regarding heavy load-handling issues (schedule TBD).
Oyster Creek:
TS changes to remove the weight restriction for liftingthe dry storage canister (DSC) shield plugs over fuel in the DSC (completed).
Watts Bar:
Design change for reracking of the spent fuel pool (currently under review).
The staff's review of the information submitted indicates that some licensees'oad-handling operations may have been implemented inconsistently with the licensing basis of the facility. Some plants either have inadvertently deviated from their load-handling procedures, implemented procedures that are inconsistent with the licensing basis, or misinterpreted the design features of their load-handling system.
The staff also believes that since the issuance of NUREG-0612, many changes have evolved in licensees'lans to handle heavy loads.
As a result, several licensees have identified changes in their load-handling operations that were not previously addressed in their licensing basis.
Therefore, on an "as needed" basis, the staff will continue to perform audits and inspections in order to evaluate licensees'ovement of heavy loads.
(4)
In o
vin S
n F
r r
C Approximately 17 percent of the plants (10 PWRs and 9 BWRs) indicated that they plan to store spent fuel dry storage casks.
Most of these plants plan to move casks within 2 years from the date of the bulletin. The remainder of the licensees either did
.not.address the issue or-have not yet begun planning for the storage of spent fuel.
(5) o dDr n
C e
I is m
Approximately 33 percent of the plants indicated that they have performed load drop and consequence analyses in support of their plans to move heavy loads.
The remaining plants did not show that any analysis exists.
In the future, the staff will review the load drop and consequence analyses on an as-needed plant-specific basis.
The staff has found that several licensees have done load drop and consequence analyses though Generic Letter 85-11 canceled Phase II of NUREG-0612, and dismissed the need for licensees to perform these analyses.
The results of the analyses have led some licensees to modify their load-handling operations, including upgrading the crane and associated components of the lifting system, and modifying the load paths.
~Co
~us'o The staff finds that NRC Bulletin 96-02 achieved its objective of getting licensees to evaluate their load-handling activities to ensure that they are performed safely and in the best interest of protecting the health and safety of the public. The bulletin was very effective in getting licensees to review their plans and capabilities, licensing bases, and regulatory guidelines for carrying out activities involving the movement of heavy loads.
Although the licensee responses to the bulletin contained various levels of detail regarding load-handling operations at their plants, sufficient information was available to enable the staff to reach the conclusions noted below.
Although several licensees have increased the reliability of their load-handling systems, the staff willcontinue to review load-handling operations, on an as-needed basis, to ensure that licensees adequately address their ability to preclude load drop accidents.
As determined through earlier NRC reviews, licensees have reliable lifting systems as required by NUREG-0612.
However, licensees need to continue to address other activities surrounding the crane operation that could help to minimize weaknesses in their load-handling operations that may contribute to load drop accidents.
Such weaknesses could include insufficient training of personnel involved in applying the lifting and rigging procedures, procedures lacking in requirements for evaluating loads and for ensuring that the design limitations of the load-lifting system are not exceeded, insufficient inspection
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~
- and preventive maintenance of cranes and lifting devices, and inadequate review of loading capacities.
Also, the staff finds that because some licensees plan to move heavy loads at power, they may need to assess their capabilities to both mitigate and manage the adverse consequences of a. heavy load drop.
Licensees should consider, among other things, possible plant shutdowns during the movement of heavy loads, limiting personnel exposure from required entry into contaminated plant areas following an accident, and recovering from the adverse conditions caused by an accident.
Accordingly, the staff is particularly interested in future evaluations of load drops and consequences associated with the load-handling 'operations"of the'licensees."
The staff also finds that several licensees have'determined, after reviewing their licensing basis, that their load-handling operations may be inconsistent with their licensing basis.
Consequently, several licensees have undertaken actions to correct or resolve this condition, including reviewing the FSAR, TS requirements, and procedures governing the conduct of operations involving the movement of heavy loads.
The staff will pursue enforcement actions for matters involving a noncompliance with regulatory requirements as appropriate.
On the basis of the preceding discussion, the staff will continue to review issues regarding the handling of heavy loads on a plant-specific basis as needed.
Generic issues regarding this subject will be addressed through an ongoing Task Action Plan (TAP) for Heavy Loads.
Any additional information required for the completion of the TAP will be obtained on a plant-specific basis.
Principal Contributor: Brian E. Thomas Date:
April 17, 1998
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ML ADAMS"HQNTAD01 ID: 003681610
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Subject:
St. Lucie Unit 1 Licensee Event Report 1999-009-00 on December 6,
1999 Appendix R Exemption Request Kl not met Resulting in Plant Outside Design Basest Body:
Page 1
Distri66.txt Docket:
- 05000335, Notes:
N/A Page 2
Florida Power & Light Company, 6351 S. Ocean Drive. Jensen Beach, FL 34957 FPL January 18, 2000 L-2000-020 10 CFR 5 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk
'ashington, D. C. 20555 Re:
St. Lucie Unit 1 Docket No. 50-335 Reportable Event: 1999-009-00 Date ofEvent: December 16, 1999 Appendix R Exemption Request KlNot Met Resultin in Plant Outside Desi n Bases The attached Licensee Event Report 1999-009 is being submitted pursuant to the requirements of 10 CFR $ 50.73 to provide notification ofthe subject event.
V ry truly yours, J. A. Stall Vice President St. Lucie Nuclear Plant JAS/EJW/KWF Attachment cc:
Regional Administrator, USNRC, Region II Senior Resident Inspector, USNRC, St. Lucie Nuclear Plant an FPL Group company
NRC FORM 366 (6-1998)
U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)
(See reverse for required number of digits/characters for each block)
APPROVED BY OMB NO. 3150 0104 EXPIRES 0613012001 Estimated burden per response to comply with this mandatory Information collection request: 50 hrs. Reported lessons learned are incorporated into lhe licensing process and fed back to induslry. Fonvard comments regarding burden estimate lo the Records Management Branch (T-6 F33), U.S. Nuclear Regulatory Commission, Washington, DC 20555.0001
~ and to the Paperwork Reduction Pro)act (31504104[,
Oflice of Management and
- Budget, Washington.
DC 20503.
If an information collection does nol display a currently valid OMB control number, the NRC may nol conduct or sponsor, and a person is not required to respond to, the information collection.
FACILITYNAME (1)
St. Lucie Unit: 1 DOCKET NUMBER (2) 05000335 PAGE (3)
Page 1 of 5 TITLE (4)
Appendix R Exemption Request Kl Not Met Resulting in Plant Outside Design Bases EVENT DATE (5)
MONTH DAY LER NUMBER (6)
YEAR SEQUENTIAL REVISION NUMBER NUMBER'ONTH DAY REPORT DATE (7)
FACIUTYNAME OTHER FACILITIES INVOLVED(8)
COCKET NuMBEII 12 16 1999 1999 - 009 00 01 2000 FACILITYNAME oocKET'uMBER OPERATING MODE (9)
POWER LEVEL (10) 100 20.2201 (b) 20.2203(a)(1) 20.2203(a)(2) (i)
- 20. 2203(a) (2)(ii)
- 20. 2203(a) (2) (v) 20.2203 (a) (3)(i) 20.2203(a)(3)(ii) 20.2203(a)(4) 50.73(a)(2)(i)
X 50.73(a)(2)(ii) 50.73(a)(2)(iii) 50.73(a) (2Hw)
THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR 5: (Check one or more)
(11) 50.73(a) (2)(viii) 50.73 (a) (2)(x) 73.71 OTHER 20.2203(a) (2)(iii) 20.2203(a) (2)(iv) 50.36(c)(1) 50.36(c)(2) 50.73(a)(2)(v) 50.73(a) (2) (vii)
Specify in Abstract below or tn NRC Form 366A NAME LICENSEE CONTACT FOR THIS LER (12)
TELEPHONE NUMBER IIneIuee Are e Corer Kenneth W. Frehafer, Licensing Engineer (561) 467 7748 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT 13I CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX NO SUPPLEMENTAL REPORT EXPECTED (14)
YES (It yes, complete EXPECTED SUBMISSION DATE).
X NO EXPECTED SUBMISSION DATE (15)
MONTH DAY YEAR ABSTRACT /Limitto 1400 spaces, i.e., approximately 15 single-spaced typewritten linesl (16)
On December 16,
- 1999, St. Lucie Unit 1 was in Mode 1 operation at 100 percent reactor power.
FPL discovered i.nconsistencies between FPL's exemption request K1 (separation criteria for redundant safe
'shutdown trains inside the Unit 1 reactor containment building) and the NRC Safety Evaluation Reports for Appendix R.
St. Lucie Unit 1 meets the separation criteria specified in its Appendix R submittals, but does not meet the 25 feet vertical separation criteria specified in the NRC SERs.
The cause of this event was personnel error during the original St. Lucie Unit 1 10 CFR 50 Appendix R licensing activities.
FPL determined that the fire protection program remains operable in this condition.
FPL will resubmit exemption request Kl to clarify vertical separation criteria.
NRC FORM 366 16-1998)
NRC FORM 3GGA (8.1888)
LICENSEE EVENT REPORT (LERI TEXT CONTINUATION
~S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1
DOCKET NUMBER (2) 05000335 LER NUMBER (B)
SEQUENTIAL REVISION NUMBER NUMBER 1999 009
00 PAGE (3)
Page 2 of 5 TEXT (Ifmore space is required, use addi donal copies of itfRC Form 366AI (17]
'escription of the Event On December 16,
- 1999, St. Lucie,Unit 1 was in Mode 1 operation at 100 percent reactor power.
FPL discovered inconsistencies between FPL's exemption request Kl to Appendix R Section XIX.G.2.d and NRC 10 CFR 50 Appendix R Safety Evaluation Reports (SERs) dated February 21,
- 1985, and March 5, 1987.
The inconsistencies pertain to the'eparation criteria for redundant safe shutdown trains inside the Unit 1 reactor containment building (RCB).
As part of the response to the NRC as required by 10 CFR 50.48 and Generic Letter 81-12, FPL submitted letters L-83-227 dated April 12,
- 1983, L-83-453 dated August 24,
- 1983, L-83-488 dated September 16,
- 1983, L-83-588 dated December 14,
- 1983, and L 346 dated November 18, 1984, to the NRC with information on the fire protection features and methodology for complying with Appendix R.
These were submitted along with request for exemptions from Appendix R as allowed in 10 CFR 50.48.
These letters stated that separation of redundant safe shutdown trains inside the RCB.was met by running the cable trays at different elevations, and formed the bases for FPL's exemption request Kl to Appendix R Section ZZI.G.2.d.
The February 21,
- 1985, SER stated that redundant cable trays were installed on separate elevations separated by approximately 25 feet.
The March 5,
- 1987, SER approved separation requirements of 7 feet horizontal and 25 feet vertically.
This is not the same information that was submitted by FPL in the above letters.
The original submittals stated that the cable trays were run at different elevations.
FPL determined that although the St. Lucie Unit 1 RCB does not meet the NRC SER requirements of 25 feet vertical separation, it does meet all applicable requirements as set forth in FPL's submittals for exemption request Kl.
Therefore, for the purpose of meeting Appendix R cable separation requirements, FPL determined that the St. Lucie Unit 1 RCB remains operable.
FPL made a
10 CFR 50.72 notification on December 16, 1999.
Cause of the Event This event was caused by personnel error during the original licensing of the St.
Lucie Appendix R program.
The original NRC SER stated that redundant cable trays were separated by a horizontal distance of more than 7 feet and that redundant cable trays were installed on separate elevations separated by approximately 25 feet.
This is not the same information that was submitted by FPL.
The original submittals stated that the cable trays were run at different, elevations.
The quoted elevati.ons were approximately 25 feet apart (i.e.,
18 feet elevation and 45 feet elevation).
The elevations referred to by FPL were not the elevations of the installed cable trays but the floor elevations inside containment.
FPL made no statement as to the exact vertical separation of redundant cable trays.
The NRC issued exemption Kl wording was interpreted to be consistent with FPL's submittals.
The second NRC SER restated the original appzoval but definitively established a new vertical separation criteria of at least 25 feet.
This was clearly not the intent of the information submitted by FPL.
FPL was deficient in that the differences between the FPL submittals and the NRC SERs were not identified during the licensing activities.
4 NRC FOAM 388A (8.18881
NRC FORM 366A (6.1998)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION
~.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER (2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
009
00 PAGE (3)
Page 3 of 5 TEXT ilfmore spaceis required, use additional copies of NRC Form 366A/ (17)
Cause of the Event (cont'd)
Since that time, St.
Lucie implemented administrative controls to ensure that during the review of incoming NRC SERs, if any differences between FPL submittals and NRC SERs are identified, that those differences are resolved.
Analysis of the Event This event is reportable pursuant to 10 CFR 50.73 (a)(2)(ii)(B) as "... any event or condition... that resulted in the nuclear power plant being...
In a condition that was outside the design basis of the plant."
St. Lucie Unit 1 cable sepazation in the RCB meets it's design bases as documented in FPL's Appendix R submittals and the UFSAR.
- However, the NRC based their approval of cable separation on an erroneous 25 feet vertical separation criteria.
Therefore, St. Lucie Unit 1 RCB cable separation is outside the NRC's bases for approval of Appendix R exemption Kl.
Analysis of Safety Significance Appendix R Section III.G.2.d requires redundant safe shutdown trains to have horizontal separation of 20 feet or greater.
St. Lucie Unit 1 was in operation prior to January 1,
- 1979, and the provisions of 10 CFR 50 Appendix R Section III.G apply to Unit 1.
Appendix R Section III'
~ 2 states that to ensure one train of equipment required for safe shutdown is free from fire damage separation for cables and equipment inside non-inerted containments shall be separated by a horizontal distance of 20 feet with no intervening combustibles or fire hazardsl or installation of fire detectors and automatic fire suppression; or separation by a non combustible radiant energy shield.
Appendix R Section -III.G.2 further states that this separation is to protect required safe shutdown equipment from maloperation of equipment of the redundant train or associated circuits.
This maloperation is defined as being caused by hot shorts, open circuits, or shorts to ground.
Information regarding the basis for maintaining one train of equipment required for safe shutdown free from fire damage is contained in multiple letters to the NRC.
Separation criteria inside containment can be summarized as at least 7 feet horizontal separation and redundant cables routed on separate trays on the 18 an'd 45 feet elevations.
The wording of the exemption with respect to separation is that separation is provided to maintain independence of electrical circuits and equipment so that the protective function required during any design basis event can be accomplished.
The degree of separation varies with the potential hazards in a particular area.
This is accomplished by use of spatial separation,
- barriers, and radiant energy shields where required.
This was the basis in the first letter submitted by FPL (L-83-277 dated April 12, 1983) and remains unchanged.
This justifiable information was repeated in later letters and is contained within the UFSAR.
.The NRC approved exemption Kl in a letter dated February 21,
- 1985, which also included a
SER.
The exemption was approved again in a letter dated March 5, 1987.
The second approval was to administratively incorporate the additional parameter of "no intervening combustibles" in the 20 feet separation area as an Appendix R Section III.G.2 requirement.
This was relevant because the approved exemption allowed intervening combustibles to exist in the space between the redundant counterparts.
The potential hazards are characterized in the latter exemption in the evaluation section which states:
NRC FORM 366A (6.1999)
NRC FORM 366A I8.1998)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION
.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER I2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
009
00 PAGE (3)
Page 4 of 5 TEXT flfmore speoe is required, uso edditionel copies of NRC Form 3MA) (17)
Analysis of Safety Significance (cont'd)
"Reaffirming our previous evaluati,on of the containment fire area and its redundant cables, it is concluded that because of the small amount of combustibles, a potential fire would be of limited magnitude and extent.
The products of combustion from such a fire would be dissipated up into the higher elevations of the containment structure and away from the vulnerable shutdown components.
Therefoxe, we conclude that one shutdown division would remain free of fire damage."
This is confirmed in the conclusion section of the exemption which states that the exemption is acceptable:
"..because the removal of combustibles in the separation space between redundant cables and associ.ated circuits would not significantly increase the level of fire protection."
Although the NRC evaluations contained in both exemptions do not site vertical separation as a significant criteria or basis for approval, an erroneous 25 feet vertical separation requirement was introduced in the March 5,
- 1987, NRC SER.
The unattainable 25 feet vertical separation concern does not constitute an operability concern.
Except for the cables previously reported in LER 50-335/1999-
- 005, redundant cables in the St. Lucie Unit 1 RCB have separation as described in previous FPL submittals to the NRC.
The NRC did not cite vertical separation as a
significant criteria or basis for approval of exemption Kl.
As stated in approved exemption Kl, the combustible loading for containment is low and i.n the area where the lack of separation occurs consists of mostly cable insulation which has a high ignition temperature.
All non IEEE cables in containment are covered with a fixe retardant coating.
The containment has a large volume with a high ceiling which would di.ssipate the hot gases from a fire to the upper area of containment away from the affected area.
The basic statement contained wi.thin exemption Kl is that the possibility of a fixe in containment is xemote and that any fixe would not affect anything except for a small localized area.
The containment is inspected prior to operation for items that could impact sump operability, therefoxe, the possibility of transient combustibles is remote.
In additi,on, the containment is a radiation area with very limited access during power operation.
The possibility of introducing new transient combustibles is very small.
The area of concern i.s primarily in the vicini.ty of the penetrations.
This area has fire detectors which would provide prompt notification of a potential fire to the control room.
Sufficient fixe fighting equipment is available to quickly extinguish any potential fire.
Therefore, any fire that should occur* should not cause significant damage
- and, as stated
- above, any damage is expected to be localized.
Fire protection for nuclear plants is based on the defense in depth concept.
The above concerns affect only the third echelon of the fire protection program.
The fi.rst two echelons (prevention of fires and prompt detection and control of fire that do occur) remain intact.
Cable separation, an Appendix R design feature, for the St.
Lucie Unit 1 RCB i.s within it's design bases as described in the UFSAR and FPL Appendix R licensing submittals for exemption Kl ~
The NRC approval for exemption Kl did not cite vertical separation as a significant basis for approval.
- However, St.
Lucie Unit 1 does not comply with the 25 feet vertical separati.on criteria, so this condition is considered in non-conformance with xespect to the NRC SER requirements.
NRC FORM 388A IB 1898)
NRC FORM 366A I6.1998)
LlCENSEE EVENT REPORT (LER)
TEXT CONTINUATION
.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME I1)
St. Lucie Unit 1 DOCKET NUMBER 2) 05000335 LER NUMBER I6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
009
00
(
PAGE I3)
Page 5 of 5 TEXT (Ifmore space is required, use additional copies of hfRC Form 388A) I17)
Analysis of Safety Significance (cont'd)
In accordance with the guidance provided in Generic Letter 91-18, the fire protection program is considered to be, operable.
Based on the above discussions, the probability of a fire is very low, the probability of a fire causing significant damage such that required functions are impaired is very low and for high/low pressure interfaces, the probability of a hot short scenario is also very low.
Based on the guidance provided in GL 91-18 the equipment and system affected by this condition can be considered operable.
Therefore, this event has no adverse effect on the health and safety to the public.
Corrective Actions 1.
FPL will resubmit exemption request Kl in order to clarify the design bases for cable separation inside the Unit 1 RCB.
Additional Information Failed Com onents Identified None Similar Events LER 50-335/1999-005, "Pressurizer Pressure Instrumentation Cable Separation Outside Appendix R Design Bases,"
documents inside containment cable separation issues with St. Lucie Unit 1.
NRC FORM 388A I8.1898)
Distribution Sheet Distri-6.txt Priority: Normal From: Elaine Walker Action Recipients:
NRR/DLPM/LPD2-2 KJabbour Copies:
Not Found Not Found Internal Recipients:
Rids Res DraaOerab RidsResDetErab RidsNrrDssaSplb RidsNrrDripRexb RidsNrrDipmlolb Rids Manager RGN2 FILE 01 RES/DRAA/OERAB RES/DET/ERAB NRR/DSSA/SPLB NRR/DRIP/REXB
~ice ca+~
ACRS 1
1 1
1 1
1 OK OK OK OK
" OK OK Not Found Not Found Not Found Not Found Not Found Not Found Not Found Not Found External Recipients:
NRC PDR NOAC QUEENER,DS NOAC POORE,W.
L ST LOBBYWARD internet: smittw@inel.gov INEEL Marshall 1
Not Found Not Found Not Found Not Found Not Found 1
Not Found Total Copies:
22.
Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID'93610024
Subject:
LER 99-008-00, "As Found Cycle 15 Pressurizer Safety Valve Setpoint Outside Technica Page 1
Distri-6.txt l Specification Limits," on 11/17/99. With letter dated 12/1 6/99.
Body:
PDR ADOCK 05000335 S Docket: 05000335, Notes: N/A Page 2
Florida Power@ Light Company,6351 S. Ocean Drive, Jensen Beach, FL34957.
December 16, 1999 L-99-278 10 CFR 5 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re:
St. Lucie Unit 1 Docket No. 50-335 Reportable Event: 1999-008-00 Date ofEvent: November 17, 1999 As Found Cycle 15 Pressurizer Safety Valve Set oint Outside Technical S ecification Limits The attached Licensee Event Report 1999-008 is being submitted pursuant to the requirements of 10 CFR $ 50.73 to provide notification ofthe subject event.
Very truly yours, J. A. Stall Vice President St. Lucie Nuclear Plant JAS/EJW/KWF Attachment cc:
Regional Administrator, USNRC Region II Senior Resident Inspector, USNRC, St. Lucie Nuclear Plant 61 y~< ~~~ oavDU99<
an FPL Group company 9'~r 3g ryan<<
NRC FORM 366 I8.1998)
U.S. NUCL R REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)
(See reverse for required number of digits/characters for each block)
APPROVED BY OMB NO. 3160-0104 EXPIRES OSI3012001 Estimated burden per response to comply with Ibis mandatory information collection request: 59 hrs. Reported lessons teamed are incorporated into tho licensing process and fed back to industry. Forward comments regarding burdon estimalo to the Records Management Branch (T-6 F33) ~ U.S. Nuclear Regulatory Commission, Washington, DC 295554981, and to the Paperwork Reduction Proiect
{31584194$,
Office of Management and
- Budget, Washington, DC 29593.
If an information collection does not display a currently valid OMB control number, Ihe NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
FACII.ITYNAME (1}
St. Lucie Unit 1 DOCKETNUMBER(2) 05000335 PAGE (3)
Page 1 of 4
TITLE (4)
As Found Cycle 15 Pressurizer Safety Valve Setpoint Outside Technical Specification Limits MONTH DAY YEAR EVENT DATE (6)
LER NUMBER 6 REPORT DATE 7)
DAY YEAR SEQUENTIAL REVISION MONTH NUMBER NUMBER FACILrTYNAME OTHER FACILITIES INVOLVED(8)
DOCKET NUMBER 17 1999 1999 008 00 1999 FACILrTYNAME DOCKET NUMBER OPERATING MODE (9)
UIREMENTS OF 10 CFR 5: (Ch'eck one or moro) (11)
ED PURSUANT TO THE REQ THIS REPORT IS SUBMITT 50.73(a) (2)(i) 50.73(a)(2)(viii}
20.2203(a) (2) (v) 20.2201 (b)
POWER LEVEL (10) 100 20.2203{a) {1) 20.2203(a) (2}(i}
20,2203(a)(2)(ii) 20.2203{a)(2)(iii) 20.2203(a)(2) (iv) 20.2203(a)(3)(i) 20.2203(a}(3)(ii) 20.2203(a)(4) 50.36(c) {1) 50.36(c) {2) 50.73(a)(2) (ii) 60.73(a}(2)(iii) 50.73(a)(2) (iv) 50.73(a)(2)(v) 50.73(a)(2) (vii) 60.73(a) (2)(x) 73.71 OTHER Specrfy rn Abstract below or in NRC Form 368A LICENSEE CONTACT FOR THIS LER (12 TELEPHONE NUMBER (Irroludo Ares Code)
Kenneth W. Frehafer, Licensing Engineer (561) 467 - 7748 COMPLETE ONE LINE FOR EACH COMPONENT FAILUREDESCRIBED IN THIS REPORT 13)
CAUSE SYSTEM.
COMPONENT MANUFACTURER REPORTABLE To EPIX CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX AB RV C170 SUPPLEMENTAL REPORT. EXPECTED (14)
YES
{IfYes, complete EXPECTED SUBMISSION DATE).
err.
X No EXPECTED SUBMISSION DATE (16)
MONTH DAY ABSTRACT fLimitto 1400spaces,i.e.,
approximately 15 single-spaced typewritten linesi (16)
On November 17,
- 1999, St:. Lucie Unit 1 was in Mode 1 at 100 percent reactor power.
Wyle Labs informed FPL of unsat:isfactory test results for code pressurizer safety valves (PSVs) removed during the cycle 16 refueling outage.
Wyle Labs was contracted to perform the offsite pressurizer safety valve testing and the testing was conducted within the required time restraints.
Technical Specification 3.4.2.1 requires the PSVs to lift at 2500 psia
(+/-1 percent).
The as found settings for two of the removed St. Lucie Unit 1 pressurizer safety valves were 3.0 percent high and 4.0 percent low, outside the Technical Specification tolerance limit of +/- 1 percent.
The cause of the failed pressurizer safety valve tests were setpoint drift and mishandling of the valves during removal or transportation.
The subject pressurizer safety valves were removed and replaced with pre-tested valves during the St. Lucie Unit 1 cycle 16 refueling outage.
There was no affect on the health and safety of the public during past St. Lucie Unit lcycle 15 power operations because the limiting overpressure analyses remain bounded when actual St. Lucie Unit 1 cycle 15 operational parameters were considered.
NRC fORM 368 ta-1998)
NRC FORM 366A (6.1998)
LlCENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S."NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER 2 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999 -
008
00 PAGE (3)
Page 2 of 4 TEXT llfmora spaceis required, use additional copies of NRC &rm366Ai (17)
Description of the Event On November 17,
- 1999, St. Lucie Unit 1 was in Mode 1 at 100 percent reactor powex'.
Wyle Labs informed FPL of unsatisfactory test xesults for code pressurizer safety valves (PSVs)
[EIIS:AB:RV) removed during the cycle 16 refueling outage.
In accordance with the inservice testing (IST) program, pressure relief devices are
'tested per ANSI/ASME OM-1987, Part 1, "Requirements for Inservice Performance Testing of Nuclear Power Plant Pressure Relief Devices."
Section 1.3.3, "Test Frequency, Class 1 Pressuze Relief Devices," of the code requires testing within 12 months of removal from service when the surveillance requirements are satisfied by installing a full complement of pre-tested valves.
Wyle Labs was contracted to perfoxm the testing and the testing was conducted within the required time restraints.
Technical Specification 3.4.2.1 requires the PSVs to liftat 2500 psia
(+/-1 percent).
The as found setting of two of the Unit 1 PSVs were outside the Technical Specification tolerance limit of +/- 1 percent.
As shown below, the deviation range for" the valves was -4.0 to 3.0 percent high.
Valve Serial Number V1200 N84217-00-0006 V12Q2 N84217-00-Q002 Set Pressure 2485 psig 2485 psig As Found Set Pressure 2559. 6 psi 2388 psig Result 3.0% High 4.0%
Low No present operability concezn exists, as all PSVs were removed and replaced with pre-tested valves during the. St. Lucie Unit 1 cycle 16 (SL1-16) refueling outage under work orders (WO) 28018286 (V1200),
28018480 (V1201),
and 28018285 (V1202).
Cause of the Event The ANSI/ASME OM-1987, Part 1,
code requires that a cause determination be performed and corrective actions implemented for any valve exceeding its nameplate setpzessure by 3 percent or greater.
Only one valve, V1200 (S/N N84217-00-0006),
met the 3
percent threshold.
The cause of the 3.0 percent high pressurizer safety valve setting for valve V1200 was mechanical setpoint drift.
Based on the limited historical block body pressurizer safety valve testing data, the actual drift over one operating cycle averages 1.4 percent.
Additionally, valve N84217-00-0006 was set on the upper end of the acceptable range when it was installed during the cycle 15 refueling outage.
The average as left setting of 2506 psig was 0.85% above the nameplate 2485 psig setting but within the +/-1% criteria.
This also contx'ibuted to the high as found setpressuze when drift is considered.
The cause of the 4.0 percent low pressurizer safety valve setting for valve V1202 was an internal misalignment problem due to mishandling.
The test data foz N84217 0002 shows that both the second and third test runs are within the +/-
1() criteria.
Based on this data, FPL concluded that the alignment problem was corrected by the first actuation.
A mechanical shock or not maintaining the valve in an upright vertical position could cause this problem.
This misalignment problem most likely occurred during removal or transportation of the valve.
NRC FORM 3BBA (9-1998)
NRC FORM 366A (0-1990),
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER (2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999 -
008
00 PAGE (3)
Page 3 of 4
TEXT iifmore spece is required, use edditionai copies of iVRC Form 366Ai (17)
Analysis of the Event FPL reviewed NUREG-1022, Revision 1, "Event Reporting Guidelines 10 CFR 50.72 and 50.73,"
and determined that this event is reportable under 10 CFR 50.73(a)(2)(i)(B) as "any operation or condition prohibited by the plant's Technical Specifications."
Although discrepancies found in Technical Specification surveillance tests should be assumed to occur at the time of the test, the existence of multiple sequential test failures involving, safety valves may be an indication that the discrepancies arose over a period of time.
Therefore, the condition may have existed during plant operation.
Analysis of Safety Significance As described in the UFSAR, Section 5.4.13.2, the reactor coolant system (RCS) is protected against overpressure by protective and control devices such as the pressurizer spray system, the power operated relief valves, and the high-pressure reactor trip.
In addition to these
- features, three ASME Code PSVs ensure that RCS piping and components are protected from overpressure in accordance with ASME Code requirements.
No present operability concern exists, as the PSVs were all removed and replaced with pre-tested valves during the cycle 16 refueling outage.
FPL and the fuel vendor performed an assessment of the accident analyses to determine if the setpoint deviations could have led to the violation of overpressuzization limits during a postulated event during operation of cycle 15.
The licensing analyses assume a +3 percent tolerance for all three PSVs in the'nalysis.
Although the -4.0 percent lift setting most likey resulted from mishandling after valve removal and did not exist during the last operating cycle, the impact on the peak primary system pressure of one safety valve lifting at 2400 psia
(-4 percent deviation) was conservatively included in t'e assessment.
Although this valve would open prior to the high pressurizer pressure trip setpoint, causing a delay in the reactor
- scram, the analysis bounds the consequences of a loss of load event with the measured safety valve tolerances.
As discussed
- above, the limiting overpzessure events were bounded once the actual. St.
Lucie Unit 1 cycle 15 operational parameters were considered in the analyses.
Therefore, FPL concludes that the as found PSV setpoints did not adversely affect the health and safety of the public during past cycle 15 operation.
Additionally, cycl'e 16 operation should be bounded by the OM-1987, Part 1,
3% code criteria taking any postulated setpoint drift into consideration.
Corrective Actions
- 1. All three St. Lucie Unit 1 PSVs were replaced with pre-tested valves during the cycle 16 refueling outage (SL1-16) via work orders (WO) 28018286 (V1200),
28018480 (V1201),
and 28018285 (V1202).
2.
FPL will revise the Wyle PSV test procedure to provide guidance to set the valves near midrange because setting the valves on the upper end of the acceptance range could challenge the code 3$ criteria.
3.
FPL is evaluating the transportation and control processes following valve removal from the unit'o determine if additional controls are necessary to prevent valve mishandling during movement.
NRC FORM 300A (0.1998)
NRC FORM 366A I6-1998)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME I1)
St. Lucie Unit 1 DOCKET NUMBER I2) 05000335 LER NUMBER IB)
SEQUENTIAL REVISION NUMBER NUMBER 1999
008 00 PAGE I3)
Page 4 of 4
TEXT Iffmore spaceis required, use additional copies of NRC Form 3MA/ I17) 4.
FPL is developing a license amendment to adopt the Standard Technical Specifications relaxed as found setpoint test criteria for pressurizer and main steam code safety valves.
Additional Znformation Failed Com onents Identified Component:
pressurizer safety valve Manufacturer:
Crosby Model:
Similar Events HB-86-BP,. forged block body design, size 3K6, assembly N84217 LER 50-389/1999-004, titled "As Found Cycle 10 Pressurizer Safety Valve Setpoint Outside Technical Specification Limits." ln this event, the cause of the test.
failure was determined to be a manufacturing problem and mechanical setpoint drift.
NRC FOAM 366A 16-1998)
,.Distribution Sheet Distri-8.txt Priority: Normal From: Elaine Walker
. Action Recipients:
, NRR/DLPM/LPD2-2
,K Jabbour Copies:
1 Not Found Not Found Internal Recipients:
RGN 2 FILE 01 RES/DRAA/0ERAB RES/DET/ERAB NRR/DSSA/SPLB
'RR/DRIP/REXB NRR/DIP M/IOLB
~LE CENTE A'CRS 1
1 1
Not Found Not Found Not Found Not Found Not Found Not Found Not Found Not Found External Recipients:
NRC PDR NOAC QUEENER,DS NOAC POORE,W.
L ST LOBBYWARD internet: smittw@inel.gov INEEL Marshall Not Found Not Found Not Found Not Found Not Found Not Found Total Copies:
16 Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 993400184
Subject:
LER 99-007-00: on 10/30/1999, manual reactor trip was noted due to low steam generato r levels during start up. Caused by personnel error. Operations management reinforced expectations. With 11/29/1999 letter.
Body:
PDR ADOCK05000335 S Page 1
Distri'8.txt Docket: 05000335, Notes: N/A Page 2
1
Florida Power & Light Company,6351 S. Ocean Drive, Jensen Beach, FL 34957
~
November 29, 1999 L-99-255 10 CFR 5 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re:
St. Lucie Unit 1 Docket No. 50-335 Reportable Event: 1999-007-00 Date ofEvent: October 30, 1999 Manual Reactor Trip Due to Low Steam Generator Levels Durin Start U The attached Licensee Event Report 1999-007 is being submitted pursuant to the requirements of 10 CFR $ 50.73 to provide notification ofthe subject event.
Very truly yours, J. A. Stall Vice President St. Lucie Nuclear Plant JAS/EJW/KWF Attachment cc:
Regional Administrator, USNRC, Region II Senior Resident Inspector, USNRC, St. Lucie Nuclear Plant
++~&it PQK I-(aCc.r
~OCG~M an FPL Group company Il)LG/: f ~i</(D/P</'
NRC FORM 366 (6-1998)
LICENSEE EVENT REPORT (LER)
(See reverse for required number of digits/characters for each block)
Estimated burden per rosponse to comply viith this mandatory information collection request: 50 hrs. Reported lessons teamed are incorporated into the licensing process and fod back to Industry. Fonvard comments regarding burden estimate to lhe Records Management Branch (TW F33) US. Nuclear Regulatory Commission, Washington, DC 20555-0001
~ and to the Paperwork Reduction Project (31500104),
Office of Management and
- Budget, Washington DC 20503.
If an information collection does nol'isplay a curronlly valid OMB control number, the NRC may not conduct or sponsor, and a person Is not required to respond to, the Information collection.
U.S. N R REGULATORY COMMISSION APPROVED B B NO. 3150-0104 EXPIRES 0613012001 FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER (2) 05000335 PAGE (3)
Page 1 of 3 TITLE (4)
Manual Reactor Trip Due to Low Steam Generator Levels During Start Up EVENT DATE (5 MONTH DAY YEAR 10 30 1999 LER NUMBER 6 SEQUENTIAL REVISION NUMBER NUMBER 1999 007 00 MONTH DAY YEAR
.29 1999 REPORT DATE (7 FACILITYNAME FACILITYNAME OTHER FACILITIES INVOLVED BI DOCKET NUMBER DOCKET NUMBER OPERATING MODE (9)
POWER LEVEL (10) 003 THIS REPORT IS SUBMITT 20.2201 (b) 20.2203(a)(1) 20.2203(a) (2) (i)
ED PURSUANT TO THE REQUIREMENTS OF 10 CFR 6: (Chock one or more)
(11) 50.73'(a) (2) (viii) 50.73(a)(2) (x) 50.73(a) (2) (i) 50.73 (a) (2) (ii) 20.2203 (a) (2)(v) 20.2203 (a) (3)(i) 73.71 50.73(a)(2)(iii) 20.2203(a) (3)(ii) 20,2203(a) (2) (ii)
- 20. 2203(a) (2) (iii)
- 20. 2203(a) (2) (iv) 20.2203(a) (4) 50.36(c)(1) 50.36(c)(2) 50.73(a)(2)(iv) 50.73 (a) (2)(v) 50.73(a)(2)(vii)
OTHER Specify ln Abstract below or In NRC Form 366A LICENSEE CONTACT FOR THIS LER 12)
TELEPHONE NUMBER Bnclude Ares Code)
Kenneth W. Frehafer, Licensing Engineer (5'61) 467 7748 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT 13 CAUSE SYSTEM COMPONENT MANUFACTurtER REPORTABLE TO EPIX CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX NO SUPPLEMENTAL REPORT EXPECTED (14 YES (If yes, complete EXPECTED SUBMISSION DATE).
X NO EXPECTED SUBMISSION DATE (15)
MONTH DAY YEAR ABSTRACT /Limitto 1400 spacos, i.e., approximately 15 single-spaced typewritten linos/ (16)
~ 'On October 30,
- 1999, St. Lucie Unit 1 was in the process of a reactor startup.
While Operations personnel were performing turnover activities, the level of the 1A steam generator began dropping and attempts to recover the 1A steam generator level were unsuccessful.
,Upon receiving annunciation of steam generator low level pre-trip alarms the reactor was manually tripped at 0641 hours0.00742 days <br />0.178 hours <br />0.00106 weeks <br />2.439005e-4 months <br />.
The plant was stabilized in Mode 3.
There were no significant equipment issues during or aftez the manual reactor trip.
The cause for the manual reactor trip was personnel error.
Operators paid insufficient attention to det:ail regarding the 1A steam generator steam flow/feed flow mismatch that resulted from unbalanced operation of the atmospheric dump valves.
Operat:ions Management reinforced expectations regarding the role of control zoom supervisors and the conduct of crew turnovers.
The plant was restarted later the same day.
Procedural enhancements will be made with regard to the role of control room supervisors and atmospheric dump valve operation.
~ NBC FOAM 366 I6.1998)
NRC FORM 366A (8-1998)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER (2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
007
00 PAGE (3)
Page 2 of 3 TEXT (Ifmore space is required, use additional copies of hfRC Form 366A) (17)
Description of the Event On October 30,
- 1999, St. Lucie Unit 1 was in the process of a reactor startup.
The unit condition just prior to taking the reactor critical was that the 1A
& 1B steam generators. were being fed by the auxiliary feedwater (AFW) system and were being steamed by the atmospheric steam dump (ADV) valves.
The 1B feedwater pump had been started at 0600 hours0.00694 days <br />0.167 hours <br />9.920635e-4 weeks <br />2.283e-4 months <br /> and was being maintained in recirculation, The operation of the ADVs was with the 1A ADV in auto and the 1B ADV in manual.
The main steam isolation valves (MSIVs) were both in the open position.
At 0614 hours0.00711 days <br />0.171 hours <br />0.00102 weeks <br />2.33627e-4 months <br /> the reactor was critical.
The original plan foz the shift was that the control room crew would conduct, turnover with zeactor power stable below the point of adding heat.
However, following criticality, control room personnel decided to
~ increase reactor power beyond three percent power (the point of adding heat:) prior to the upcoming shift turnover.
At 0630 hours0.00729 days <br />0.175 hours <br />0.00104 weeks <br />2.39715e-4 months <br /> the reactor startup had reached the point of adding heat and the reactor was believed to be stable.
At this time dayshift Operations personnel were arriving in the control zoom ready to take over operation/startup of the unit.
Believing that the unit was stable, turnover activities began.
While Operations personnel were performing turnover activities the level of the lA steam generator began dropping.
After the level decrease was noted, operator actions to recover the 1A steam generator level were unsuccessful.
Upon receiving annunciation of steam generator low level pre-trip alarms the operators manually tripped the reactor at 0641 hours0.00742 days <br />0.178 hours <br />0.00106 weeks <br />2.439005e-4 months <br />.
The plant was stabilized in Mode 3 ~
'There were no significant equipment issues during or after the manual reactor trip.
,St. Lucie Unit 1 was restarted later the same day without incident.
An event response team (ERT) was formed to perform root cause analysis.
Cause'f the Event When the unit tripped, the 1A ADV was in automatic and the 1B ADV was in manual control.
When power was increased the output on the 1B ADV and steaming rate on the 1B steam generator remained unchanged while the output on the 1A ADV and steaming rate on the 1A steam generator was increased.
This mismatch was not immediately recognized and addressed, which caused a drop in level in the 1A steam generator as power was increased.
The crew did not comply with the expectations and procedural xequirements for crew tuznover in that. stable conditions were not adequately verified.
Factors contributing to this event include:
- 1) Supervisory oversight was not adequate and did not ensure that individual roles and responsibilities were clearly defined and communicated.
2)
The control room turnover that was in progress distracted from the evolution in progress.
~
- 3) A decision was made at the end of the shift to proceed beyond the point of adding heat.
No additional crew briefing was conducted prior to this evolution and the impact of this decision on achieving stable plant conditions during turnover was not fully evaluated.
- 4) Procedural guidance regarding operation of the ADVs was inadequate; specifically, steam generator blowdown status, cautions to balance the ADVs and maximum power levels for AFW and ADV operation.
NRC FORM 386A (6.1998)
NRC FORM 366A (8.1998)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME(1)
St. Lucie Unit 1 DDGKET NUMBER (2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999,007
00 PAGE (3)
Page.3 of 3 TEXT (Ifmore space is required, use addi fional copies of NRC Form 366Al (17)
Analysis of the Event
'his event is reportable under 10 CFR 50.72(a)(2)(iv) as "... any event or condition that resulted in a manual or automatic actuation of any, Engineered Safety Feature (ESF) including the Reactor Protection System (RPS)..."
Analysis of Safety Significance This steam generator low level transient'was caused by a steaming rate greater than feedwater flow.
The failure to maintain the 1A steam generator water level resulted in a manual trip of the reactor.
The plant responded correctly to the trip, and no significant equipment issues were identified.
Corrective Actions 1)
The Operations Manager met with the key Operations personnel directly involved in this event, including supervisors, to specifically review their contributions to this event and how it could have been avoided.
2)
The Operations Night 'Orders for November 1,
1999, included a briefing summary on this event.
These orders also included additional guidelines for the conduct of crew tuznovers.
Operating crews were briefed on the lessons learned from this event prior to standing watch.
The subsequent staztup proceeded without incident.
- 3) Procedure AP-0010120, "Conduct of Operations," will be improved.
Specifically, guidance will be provided in regard to the supervisor's role in recognizing vulnerable plant conditions and the assignment of resources to mitigate the vulnerability.
Inherent in this guidance will be direction to ensure roles and responsibilities for operating personnel are clearly defined.
This guidance will be reinforced during continuing operator license training.
- 4) Plant operating procedures will be revised to include additional guidance on the use of the plant atmospheric dump valves.
Unit 2 operating procedures will also be examined for this need.
- 5) Operations will evaluate with Training the need for a specific training module for Unit 1 ADV operation including training on ADV controller response.
Additional Information Failed Com onents Identified None Similar Events None NRO FORM 388A I8-1998)
Distribution Sheet Distri48.txt r//~Yi~l Priority: Normal From: Elaine Walker Action Recipients:
NRR/DLPM/LPD2-2 K Jabbour Copies:
I Not Found Not Found Internal Recipients:
RGN 2 FILE 01 RES/DRAA/OERAB RES/DET/ERAB NRR/DSSA/SPLB NRR/DRIP/REXB NRR/DIPM/IOLB FILE CENTER ACRS 1
1 1
1 Not Found Not Found Not Found Not Found Not Found Not Found Not Found Not Found External Recipients:
NRC PDR NOAC QUEENER,DS NOAC POORE,W.
L ST LOBBYWARD internet: smittw@inel.gov INEEL Marshall Not Found Not Found Not Found Not Found Not Found Not Found Total Copies:
16 Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 993400408
Subject:
LER 99-006-00, "Turbine/Reactor Trip Due to Ruptured Turbine Low Bearing Oil Trip Dia phragm." With 991124 Letter.
Body:
PDR ADOCK05000335 S Page 1
Docket: 05000335, Notes: N/A Dtstrlas.txt Page 2
Florida Power 5 Light Company, 6351 S. Ocean Drive. Jensen Beach, FL 34957 FPI November 24, 1999 L-99-254 10 CFR g 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re:
St. Lucie Unit 1 Docket No. 50-335 Reportable Event: 1999-006-00 Date ofEvent: October 29, 1999 Turbine/Reactor Trip Due to Ruptured Turbi w B rin il Tri Dia hra The attached Licensee Event Report 1999-006 is being submitted pursuant to the requirements of 10 CFR g 50.73 to provide notification ofthe subject event.
Very truly yours, J.A. Stall Vice President St. Lucie Nuclear Plant JAS/EJW/KWF Attachment cc:
Regional Administrator, USNRC, Region II Senior Resident Inspector, USNRC, St. Lucie Nuclear Plant
NRC FORM 366 I6.1998)
U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)
{See reverse for required number of digits/characters for each block)
APPROVED BY OMB NO. 3150.0104 EXPIRES 06I3012001 Estimated burden oer response to comply with this mandatory Information collecaon request: 50 hrs. Reported lessons learned are incorporated into the licensing orocess and fed back to industry. Forward comments regarding burden eslimate lo the Records Management Branch (TW F33), US. Nudear Regulatory Commission, Washington, DC 205554001
~ and to the Popetvxxh Reduction Proiect (3t500IOE),
Office of Management and
- Budget, Washington.
DC 20503.
If an lnfonnatlon coltecdon does not display a currently valid OMB contml number, lhe NRC may nol conduct or sponsor, and a person Is nol required to respond to, the information cogection.
FACIUTY NAME (1)
St. Lucie Unit 1 DOCKET NUMBER l2) 05000335 PAGE (3)
Page 1 of 4 TITLE (4)
Turbine/Reactor Trip Due to Ruptured Turbine Low Bearing Oil Trip Diaphragm EVENT DATE (5 DAY LER NUMBER 6 SEQUENTIAL REVISION NUMBER NUMBER REPORT DATE 7)
FACIUTYNAME OTHER FACILITIES INVOLVEDIBI DOCKET NVMBEn 10 29 1999 1999 -'06
00 11 24 1999 FACIUTYNAME DOCKETNUMBEA OPERATING MODE (9)
UIREMENTS OF 10 CFR 5: (Check THIS REPORT IS SUBMITTED PURSUANT TO THE REQ 20.2203(a) l2)(v) 50.73(a) (2) (i) 20.2201(b) one or more) l11) 50.73(a) (2)lviii)
POWER LEVEL (10) 100 20.2203 (a) (1) 20.2203(a)(2)(i) 20.2203(a) (2)(ii)
- 20. 2203(a) (2)liii) 20.2203(a)(2)(iv) 20.2203(a) l3)(i)
- 20. 2203(a) (3)(ii) 20.2203(a) (4) 50.36(c) l1 )
50.36(c)(2) 50.73(e) (2)(ii) 50.73(a)(2)(iii)
X S0.73(o)(2) liv) 50.73(a) (2)(v) 50.73(a)(2) lvii) 50.73(a) (2)(x) 73.71 OTHER Specify In Abstract below or In NAC Form 368A NAME UCENSEE CONTACT FOR THIS LER 12)
TELEPHONE NUMBOt anotueo Atoo Codot Kenneth W. Frehafer, Licensing Engineer t561) 467 - 7748 COMPLETE ONE UNE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT 13 CAUSE SYSTEM COMPONENT MANUFACTURER AE PORTABLE To EPIX CAUSE SYSTEM COMPONENT MANUFACTURER REPOATAB(E TO EPIX TG BLL W120 YES SUPPLEMENTAL REPORT EXPECTED (14)
YES llfyes, complete EXPECTED SUBMISSION DATE).
NO EXPECTED SUBMISSION DATE (15)
MONTH DAY ABSTRACT /Limitto 1400 spaces, i.e., approximately 15 singie-spaced typewritten IinesJ (16)
On October 29, 1999, St. Lucie Unit 1 was in Mode 1 at 100 percent reactor power.
At 0105 hours0.00122 days <br />0.0292 hours <br />1.736111e-4 weeks <br />3.99525e-5 months <br /> the St. Lucie Unit 1 control room received annunciation of D-12 "Turbine Bearing Oil Pressure Low."
Operations personnel discovered that a small amount (approximately two drops per minute) of oil was leaking from the cover of the turbine
,,protective device trip block.
The turbine/generator and reactor automatically tripped at 0129 hours0.00149 days <br />0.0358 hours <br />2.132936e-4 weeks <br />4.90845e-5 months <br />.
Standard post trip actions were carried out and the reactor was stabilized in Mode 3.
The cause of this event was the installation of a Westinghouse supplied defective diaphragm for the turbine low bearing oil trip protective device.
The failure of this diaphragm dumped the autostop oil pressure and tripped the turbine/generator.
The loss of autostop oil pressure resulted in the;opening of the DEH interface valve, dumping all DEH oil pressure.
The loss of DEH oil pressure resulted in the automatic trip of the reactor.
The faulty diaphragm was replaced and miscellaneous minor equipment issues were dispositioned.
NAC FOAM 366 IS 1998)
')RC FORM 366A 6 1898)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER I2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999 -
006
00 PAGE (3)
Page 2 of 4
TEXT iifmore speceis required, use eddidonel copies ofiVRC Farm 3664) l17)
Doscziption of the Event On October 29, 1999, St. Lucie Unit 1 was in Mode 1 at 100 percent reactor power.
At 0105 hours0.00122 days <br />0.0292 hours <br />1.736111e-4 weeks <br />3.99525e-5 months <br /> the St. Lucie Unit 1 contxol room received annunciation of D-12 "Turbine Bearing Oil Pressure Low."
Operations personnel immediately performed a visual
'inspection of the turbine/generator and found that all indicated bearing oil pressures were satisfactory.
Further inspections discovered that a small amount (approximately 2idrops per minute) of oil was leaking from the cover of the turbine protective device trip block. While Operations personnel were discussing the actions to be taken the turbine/generator and reactor automatically tripped at 0129 hours0.00149 days <br />0.0358 hours <br />2.132936e-4 weeks <br />4.90845e-5 months <br />.
Standard post trip actions were carried out and the reactor was stabilized in Mode 3.
There were no problems identified with any of the safety related systems following the reactor trip and the turbine/generator trip was not caused by any safety related or primary side equipment.
After the turbine trip maintenance personnel removed the cover on the turbine protective device trip block and discovered that the oil leak
'as from around the low bearing oil trip zod where it enters the low bearing oil trip diaphragm flange.
Additional minor issues following the Unit 1 trip were identified as listed below:
1.
- SR09209, the 5B feedwater heater tube side relief valve, lifted, 2 ~ The 2A and 2B main feedwater pumps both tripped upon the reset of the 15 percent feedwatez bypass valves,
- 3. Auxiliary feedwatez actuation signal (AFAS) operation abnozmalitiesr and
- 4. Turbine contxol system oil leaks at PS-22-117 and at the 'B'ntercept valve.
Cause of the Event The cause for the turbine/generator automatic trip was the failure of the.low bearing oil trip diaphragm
[EIIS:TG:BLL].
The failure of this diaphragm allowed the low bearing oil trip compression spring to reposition the low bearing oil trip rod resulting in the solenoid trip pin unseating, dumping autostop oi.l pressure and tripping the turbine/generator.
The loss of autostop oil pressure resulted in the opening of the DEH interface valve, dumping all DEH oil pressure.
The loss of DEH oil pressure resulted in the. automatic trip of the reactor.
. The low bearing oil trip diaphragm was found tom.
Examination of the diaphragm found that it had failed partially or completely for approximately 7/8 of the circumference of the diaphragm area exposed to the autostop oil.
Comparison of this diaphragm with the three diaphragms removed during SLl-16 outage found that this diaphragm is made of different material and has a different thickness than the diaphragms removed during the outage.
The Westinghouse supplied diaphragm was of the wrong material.
The defective diaphzagm was replaced.
Cause of Miscellaneous E ui ment Issues 1.
SR09209 (5B FW Heat Exchanger Tube Si.de Relief Valve)
Investigation revealed that the relief valve lifted momentarily (within its design tolerance) duri.ng the higher than normal plant conditions experienced during a
plant trip.
NAC FOAM 388A I8 1999)
'JRC FORM 366A 8.1888)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION IeI U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1
DOCKET NUMBER I2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
006 00 PAGE (3)
Page 3 of 4 TEXT llfmore spece is required, use eddfdonel copies of NRC Form 3664 / (17)
Cause of the, Event (cont'd) 2.
3.
Main Feedwater Pump Trips A minor modification was performed to the feedwatez (FW) recirculation system during the 1999 fall St. Lucie Unit 1 refueling outage to prevent low flow trips of the main 'feedwater pumps in response to a turbine trip.
Prior to the modification, the FW recirculation valves were not opening fast enough to avoid reaching the pump low flow setpoint during the transient while the main FW control valves were closing in response to the turbine trip.
This modification added a
turbine trip input signal from the FW bypass valve circuitry to the fail open logic of the FW recirculation control valves.
The design of this circuit includes pushbutton turbine trip reset switches that allow the operator to take manual control of the bypass valves.
Depressing these reset pushbuttons restores contxol of the FW recirculation valves to either the FW pump control switch (if in the RECIRC position) or to the automatic controller (if in the AUTO RECIRC position).
The controller setpoint was also raised to 4500 gpm (the maximum calculated recirculation flowrate) to ensure that the recirculation valves would remain open (regardless of the position of the FW pump control switch) after the turbine trip reset pushbutton was depressed.
Procedurally, the operators aze required to place the FW pump control switch in RECIRC when feedwater flow is less than 10,000 gpm.
During this,event the FW pump control switch was in AUTO RECIRC when the operators reset the turbine tzip.
The actual recirculation flow was approximately 6000 gpm.
The controller drove the FW recirculation valve closed and undershot the desired 4500 gpm flowrate and a trip of the main feedwater pumps resulted from low flow conditions.
Warning placards were placed near the turbine trip reset pushbuttons to ensure the FW pump control switch is placed in RECIRC prior to resetting a
AFAS Reset Time Operations'dentified that the AFAS Channel C steam generator-1A low level trip signal did not reset in the same time frame as the other AFAS level channels.
Based upon this problem definition, IEC maintenance checked that the AFAS level reset was properly calibrated for AFAS steam generator-1A channel MC (Work Order 99019908)
Further investigation revealed that the reactor protection system (RPS) steam generator low level trip signal for channel MC also did not reset until the same delayed time frame as AFAS steam generator 1A channel MC.
ERDADS post-trip data was retrieved for the steam generator narrow range level channels.
A review of this data indicated that the L-9013C loop was reading lower than the other narrow range level channels by approximately one percent of span during the post-trip recovery of steam generator level.
When the auxiliary feedwater system had returned steam generator 1A level to above the AFAS reset point all of level channels reset except Channel C.
The reset of the three of the four steam generator 1A level signals resulted in the zeset of the AFAS-1 signal terminating AFW flow to steam generator 1A.
Due to the termination of AFW flow, steam generator 1A level did not get high enough to reset AFAS steam generator 1A channel MC until later when operators manually increased the steam g'enezator 1A level.
The AFAS and RPS functioned properly in response to the decrease in steam generator level.
The steam generator 1A channel C level trip signals actuated at NRC FORM 3BBA IB 1888)
'NRC FORM 366A (8 1898)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER 2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999 -
006 00 PAGE (3)
Page 4 of 4
TEXT llfmore speceis required, use edditionel copies of NRC Form 36EAi (17)
Cause of the Event (cont'd) the correct setpoints.
The time delay in resetting the steam generator 1A Channel C level trip signals was due to a minor difference in the measured level.
- 4. Turbine Control Oil Leaks A DEH leak was identified and at the 'B'ntercept valve and a turbine auto stop oil leak was found at PS-22-117, the emergency trip auto stop oil pressure switch.
The 'B'CV-10-039 pipe plug was tightened.
The leak at PS-22-117 was repaired via Work Order 99019379.
Analysis of the Event
~
This event is reportable under 10 CFR 50.72(a) (2) (iv) as "... any event or condition that resulted in a manual or automatic actuation of any Engineered Safety Feature (ESF) including the Reactor Protection System (RPS)..."
Analysis of Safety Significance All safety systems responded to the turbine/generator trip as designed.
Therefore, this event had no impact to the health and safety of the public."'orrective Actions 1.
The three potentially defective diaphragms were replaced under Work Order
- 99019906,
- 2. Warning placards were placed near the turbine trip reset pushbuttons to ensure the FW pump control switch is placed in RECIRC prior to resetting a turbine trip.
3.
The turbine control oil leaks were repaired (the leaking DEH pipe plug on the
'B'ntercept valve was tightened under Work Order 99019738 and the turbine control auto stop oil leak at PS-22-117 was repaired under Work Order 99019379).
Additional Information I
Failed Com onents Identified Component:
Low Bearing Oil Trip Protective Device Diaphragm Manufacturer:
Westinghouse Part No.
268A111001 Similar Events None NRC FORM 388A I8 18881
(ikey Distri87.txt Distribution Sheet Priority: Normal From: Andy Hoy Action Recipients:
W Gleaves NRR/DLPM/LPD2-2 Copies:
1 1
Not Found Not Found
,Internal Recipients:
RGN 2.FILE 01 RES/DRAA/OERAB RES/DET/ERAB NRR/DSSA/SPLB NRR/DRIP/REXB NRR DIPM IOLB LE CENTE Not Found Not Found Not Found Not Found Not Found Not Found Not Found Not Found External Recipients:
NRC PDR NOAC QUEENER, DS NOAC POORE,W.
L ST LOBBY WARD internet:
smittw8inel.gov INEEL Marshall 1
1 1
1 1
1 Not Found Not Found Not Found Not Found Not Found Not Found Total Copies:
Item:
ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 993140235 16
Subject:
Pressurizer pressure instrumentation cable separation outside App R de sign bases Body:
Docket:
- 05000335, Notes:
N/A Page 1
Florida Power tL Light Company, 6351 S. Ocean Drive, Jensen Beach, FL 34957 November 1, 1999 I 99-238 10 CFR $ 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re:
St. Lucie Unit 1 Docket No. 50-335 Reportable Event: 1999-005-00 Date ofEvent:
October 5, 1999 Pressurizer Pressure Instrumentation Cable Se aration Outside A endix R Desi n Bases The attached Licensee Event Report 1999-005 is being submitted pursuant to the requirements of 10 CFR f 50.73 to provide notification ofthe subject event.
Very truly yours,
. A. Stall Vice President St. Lucie Nuclear Plant JAS/EJW/KWF Attachment cc:
Regional Administrator, USNRC, Region II Senior Resident Inspector, USNRC, St. Lucie Nuclear Plant en FPL Group company
(6-1998)
U.S. N AR REGULATORY COMMISSION APPROVED B NO. 3150-0104 EXPIRES 06/30/2001 LICENSEE EVENT REPORT (LER)
(See reverse for required number of digits/characters for each block)
Estimated burden per response to comply with this mandatory Information collection request: 50 hrs. Reported lessons learned are incorporated into the licensing process and fed back to industry. Forward comments regarding burden estimate to the Records Management Branch (TW F33) U.S. Nuclear Regulatory Commission, Washington, DC 2055&0001, and to t)ro Paperwork Reduction Project (31500104),
Office of Management
~ and
- Budget, Washington DC 20503.
If an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER (2) 05000335 PAGE (3)
Page 1 of 6 TITLE (4)
Pressurizer Pressure Znstrumentation Cable Separation Outside Appendix R Design Bases EVENT DATE (SI MONTH'AY YEAR 10 05 1999 LER NUMBER 6)
SEQUENTIAL REVISION NUMBER NUMBER 1999 005
00 REPORT DATE 7)
MONTH DAY YEAR 11 01 1999 FACIUTYNAME FACIUTYNAME OTHER FACILITIES INVOLVED(BI DOCKET NUMBER OOCKET NUMBER OPERATING MODE (9)
POWER LEVEL (10) 000 20.2201 (b) 20.2203(a) (1) 20.2203(a)(2) (i) 20.2203 (a) (2) (ii) 20.2203(a) (2) (iii) 20.2203 (a) (2) (iv) 20.2203(a) (2)(v) 20.2203(a) (3)(i) 20.2203(a) (3)(ii) 20.2203(a) (4) 50.36(c)(1) 50.36(c) (2) 50.73(a)(2)(i)
X 50.73(a)(2)(ii) 50.73(a)(2)(iii) 50.73(a)(2)(iv) 50.73(a)(2)(v)
S0.73(a)(2)(vii) 50.73(e) (2)(viii) 50.73 (a) (2)(x) 73.71 OTHER Specify in Abstract below or In NRC Form 366A k one or moro) (11)
ED PURSUANT TO THE REQUIREMENTS OF 10 CFR g:
(Ghee THIS REPORT IS SUBMITT NAME LICENSEE CONTACT FOR THIS LER 12)
TELEPHONE NUMBER Bnolude Area Coda)
Kenneth W. Fzehafer, Licensing Engineer (561) 467 - 7748 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT CAUSE SYSTEM COMPONENT MANUFACTURER NA REPORTABLE TO EPIX NO P;
K'rgc CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX SUPPLEMENTAL REPORT EXPECTED (14)
YES (If yes, complete EXPECTED SUBMISSION DATE).
X No EXPECTED SUBMISSION DATE (15)
MONTH DAY ABSTRACT lLimitto 1400 spaces, i.o., eppreximetoly 15 single-spaced typewritten lines/ (16)
On October Sr 1999r St Lucie Unit 1 was in Mode 6 during a refueling outage.
FPL engineers finished their initial assessment of the inside containment Appendix R cable separation walkdowns.
This walkdown was planned as part of the continuing safe shutdown analysis validation effort.
The assessment:
results showed that pressurizer pressure instrumentation did not meet the required 10 CFR 50 Appendix R cable separation criteria inside containment at the penetration area where the cables for pressurizer pressure transmitters PT-1102B and D
pass over the penetrations for PT-1102A and C.
FPL determined that this 10 CFR 50 Appendix R noncompliance does not adversely affect the fire protection program, and that t:he pressurizer pressure instrumentation remains operable wit:h respect to the required safe shutdown functions.
Modifications required to place the field condition within design basis conditions will require extensive engineering, procurement and construction time, and are planned to be performed during the next St. Lucie Unit 1 refueling outage.
NRC FORM 3GG (6.1998)
NRC FORM 366A (6-1996)
LlCENSEE EVENT REPORT (LER)
TEXT CONTINUATION.
U.S. NUCLEAR REGULATORY COMMISSION FAGILITYNAME(1)
St. Lucie Unit 1 DOCKET NUMBER I2) 05000335 LER NUMBER I6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
005
00 PAGE I3)
Page 2 of 6 TEXT (ifmore space is required, use additions/ copies of NRC Form 38bA/ (17)
Description of the Event On October 5,
- 1999, St. Lucie Unit 1 was in Mode 6 during a refueling outage.
FPL engineers fini:shed their initial assessment of the inside containment Appendix R
cable separation walkdowns
~
This walkdown was planned as part of the continuing safe shutdown analysis (SSA) validation effort.
The results of the walkdown were evaluated to the following separation requirements:
~
7 feet horizontal and on diff'erent floor elevations (exemption K1)
, or
~
20 feet horizontal with no intervening combustibles (III.G.2.d)
., or
~
separated by a radiant energy shield (III.G.2.f)
The first requirement is based on the correspondence submitted to the NRC in support of exemption K1.
Specifically, letter L-83-488 dated September 16, 1983, called out specific sepazation for cables in cable trays.
This letter stated that redundant cables in cable trays weze separated by 7 to 11 feet horizontally and run at different elevations (i.e.
one cable in a tray at El.
18 feet with the redundant cable in a tray at El.
45 feet.
The exceptions to this are the power operated relief valves (PORVs) which were stated to be on the same elevation (45 feet) and protected by lower trays which act as radiant energy shields.
The SER that approved exemption K1 stated that redundant cable trays were separated by a horizontal distance of more than 7 feet and run at different elevations.
The UFSAR does not have these requirements, but it is clear from the SER that the NRC approval was based on these requirements.
Therefore, FPL conservatively applied these requirements for cable separation in containment.
The assessment results showed that the pressurizer pressure instrumentation did not meet the required cable separation criteria for some areas of containment.
FPL letter L-83-488 stated that zedundant pressurizer pressure transmitters aie located on elevations 23 and 62 feet with cables routed in separate trays on the 18 and 45 feet elevation with greater than 7 feet horizontal separation.
It appears that this
~
is generally true except for the penetration area where the cables for pressurizer pressure transmitters
[EIIS:AB:PT) PT-1102B and D pass over the penetzations foz PT-1102A and C.
Additionally, pressurizer control system pressurizer pressure transmitters 1100K and 1100Y also lack cable separation.
Therefore the requirements for exemption Kl are not met.
FPL determined that this 10 CFR 50 Appendix R noncompliance does not adversely affect the fire protection program, and that the pressurizer pressure instrumentation remains operable with respect to the required safe shutdown functions.
Modifications required to place the field condition within design basis conditions will require extensive engineering, procurement and construction time, and will be performed during the next scheduled refueling outage.
Cause of the Event The cause of this event is the fact that the original design basis was not adequately documented when the information was submitted to the NRC.
Reliance on this information resulted in the SSA not considering several aspects of equipment and cable separation within containment.
The source of the design basis is not clear.
Current procedures require better documentation and would have alleviated these concerns should they have been in effect at the time the original work was performed.
NRC FORM 366A (6-1999)
NRC FORM 366A (6-1998)
LlCENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER (2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
005
00 PAGE (3)
Page 3 of 6
,-TEXT (Ifmoro spaeeis required, use additional copies of NRC Form 366AJ (17)
Analysis of the Event The condition noted above is reportable with respect to 10 CFR 50.73(a)(2)(ii)(B) as "Any event ox condition that resulted in... the nuclear power plant... being in a condition that was outside the design basis of the plant."
The walkdown results document that pressurizer pressure instrumentation cabling does not meet the design bases for cable separation as delineated in the UFSAR and in letters to the NRC demonstrating Appendix R compliance.
The lack of sepazati'on at the penetration azea does not meet the requirements of Appendix R ZII.G.2 nor the requirements of exemption Kl.'lthoughthis condition was discovered when St. Lucie Unit 1 was shutdown during a
refueling outage, this condition was not corrected prior to the uni.t restart from the Fall 1999 refueling outage.
As this would result in operation of the plant outside its design bases, FPL conservatively notified the NRC of this condition prior to restart in accordance with 10 CFR 50.72(b)(1)(iii.)(B) on October 14, 1999, prior to unit restart.
Analysis of Safety Significance Fire protection for nuclear plants is based on the defense in depth concept.
The above concerns affect only the third tier, Appendix R design features (i.e., cable separation) of the fi.re protection program.
The first two echelons (prevention of fires and prompt detection and suppression of fires that do occur) remain intact.
The lack of cable separation does not eliminate fire protection defense in depth, but instead is const.dered a degradation in the ability to safely shutdown should a fire occur that could not be controlled.
Howeyexr as outlined below, the probability foz such a fire inside containment during power operation is remote.
As stated in the correspondence for approved exemption K1, the combustible loading foz containment is low and in the area where the lack of separation occurs consists of mostly cable insulation which has, a high ignition temperature.
All non-IEEE 383 cables are covered with a fire retardant coating.
The containment has a large volume with a high ceiling, which would dissipate the hot gases from a fire to the upper area of containment away from the affected area.
The basic statement contained within exemption Kl is that the possibility of a fire in containment is remote and that. any fire would not affect anything except for a small localized area.
The containment is inspected prior to operation.for items that could impact sump operability; therefoxe, the potential for transient combustibles is precluded.
Zn addition, the containment is a radiation contzol area as well as a foreign material exclusion area with very limited access during power operati.on.
The possibility of introducing new transient combustibles is very small.
The area of concern is from column line 1 to 7 (radiant energy shield) outside the biological shield wall.
This area has fire detectors that would provide prompt notification of a fire to the control room.
Sufficient fire fighting equipment is avai.lable to extinguish any potential fire.
Therefore, any fire that is postulated to occur should not cause significant damage and any damage is expected to be localized.
10 CFR 50 Appendix R ZZZ.G.2 states that cable separation protects required safe shutdown equipment from maloperation of equipment of the redundant train or associated circuits.
This maloperation is defined as being caused by hot shorts, open circuits, or shorts to ground.
In the event of a postulated fixe inside containment, circuit failures could cause the pressure transmitters to spuriously provide abnormal signals to the reactor protection system (RPS) high pressurizer pressure bistable trip units, the thermal margin/low pressure bistable trip units,.
NAC FOAM 3BBA IB-1998)
NRC FORM 366A (6.1998)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGUlATORY COMMISSION FACILITYNAME (1)
St. Lucie Unit 1 DOCKET NUMBER (2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
005
00 PAGE (3)
Page 4 of 6 TEXT (Ifmore spaceis required, use additional copies ofiVRC Form 366Ai (17)
Analysis. of Safety Significance (cont'd) the engineered safety features actuation system (ESFAS) cabinet for use in the safety injection and diverse scram system actuation logic, low-low alarm function, and pressurizer pressure control system.
In addition, contxol room indication of pressurizer pressure could be compromised.
S urious E ui ment 0 eration Considerations PT-1102A, PT-1102B, PT-1102C and PT-1102D are safety related. narrow range (1500
~ 2500 psia) pressurizer transmitters for the pressurizer pressure measurement loops.
The narrow range pressurizer pressure instrument loops provide a signal to the RPS high pressurizer pressure bistable trip units,
~ the thexmal margin/low pressure bistable trip units, the ESFAS cabinet for use in the safety injection and diverse scram system actuation logic, low-low alarm function, and control room indication. In
- addition, cables fox the pressurizer transmitters, which are input to the pressurizer pressure control system, are routed in the same manner as the other pressurizer pressure transmitters.
For design basis accident mitigation (UFSAR Chapter 15), the pressurizer pressure transmittexs are not impacted and remain operable.
Using the separation criteria per exemption Kl, a fire in the penetration area of containment at elevation 23 feet-0 would affect pressurizer transmitters PT-1102A (cable 10372A+-MA)r PT-1102B (cable 10373A+-MB), PT-1102C (cable 10374A+-MC) and PT-1102D (cable, 10375A*-MD). The identified cables provide the interface between the protection system pressurizer pressure transmitters and the remaining portions of each instrument loop.
Depending on the cable failure mode the pressure signals could fail either high or low.
If two or more channels failed in the high direction, the following actions would occur:
~
A reactor trip on high pressurizer pressure would occur.
~
PORV open signals would be generated.
Spurious operation of PORVs is precluded by placing the PORV control switches in override and by isolation of PORV block valves V1402 and V1404.
These actions are currently in the response to fire procedure fox an in-containment fire.
If two or more channels failed in the low direction, the following actions would occur:
~
A reactor trip on thermal margin/low pressure (TM/LP) would occur.
~
Safety injection and containment isolation would actuate.
The response to fire procedure currently contains compensatory measures for a spurious safety injection actuation system (SIAS) signal.
In addition, the same fire could potentially affect pressure transmitters PT-1100X and PT-1100Y that provide input to the pressurizer pressure" control system.
Damage to PT-1100X and PT-1100Y could potentially cause spurious operation of the pressurizer spray valves and/or pressurizer heaters.
In the event that this control is lost, manual control will be used for the pressurizer heaters and the appropriate reactor coolant pumps (RCPs) will be stopped to prevent excessive spray flow.
These manual actions are addressed in the SSA.
NAG FOAM 3BBA IB.1998)
~
NRC FORM 366A I0-1888)1'ICENSEE EVENT REPORT (LER)
TEXT CONTINUAT)ON U.S. NUCLEAR REGULATORY COMMISSION FAGILITYNAMEl1)
St. Lucie Unit 1 DOCKET NUMBER I2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
005
00 PAGE (3)
Page 5 of 6 TEXT fifmore spaceis rerluired, use additional copies of NRC Form 366AJ l17)
Analysis of Safety Significance (cont'd)
Loss of Pressurizer.
Pressure Indication Considerations Interpreting the protection requirements for cable trays carrying pressurizer pressure instrument cables in the same manner as described and accepted for high/low pressure interface cable trays yields the following:
~
Between column lines 1 and 5, as well as between column lines 6 and 7, cable-trays
- M120, C120 and L120 are located below cable tray L131, which contains the cable for PT-1104 (low range),
PT 1102D (high range) and PT-1108 (wide range).
- Thus, these circuits would be considered functional post fire.
~
Between column lines 1 and 6, high range (PT-1102C) and wide range (PT-1108) meet the separation requirements.
~
Between column lines 1 and 7 the cable trays for redundant wide range and low range pressurizer pressure indication are greater than 7 feet apart and above the 45 feet elevation.
This is over 25 feet from the floor elevation.
No credible fire can affect the cables in these trays in an open environment such as containment; thus this indication will be available.
Based on the above, the probability of a fire causing significant damage such that all pressurizer pressure indication is impaired is very low. It is clear from the preceding discussion that the loss of all pressurizer pressure indication is not credible.
- However, the St. Lucie Unit 1 fire response procedure was revised to provide the operators with the following alternative primary system pressure indication in the incredible event all pressurizer pressure indication is lost:
'C
~
Charging line pressure indication PIA-2212 '(0-3000 psia),
or
~
Primary sample line pressure gauge,.
PI-5510 (0-3000 psia).
Conclusion In summary, the safety significance of this condition is very low as is the probability of a fire in containment.
Should a fire occur, spurious equipment operation due to postulated failures of pressurizer pressure instrumentation is already addressed in the St, Lucie Unit 1 SSA.
Additionally, in the incredible event that all pressurizer pressure indication is lost, alternate means of reactor coolant system (RCS) pressure indication are available.. Therefoxe, this event had no adverse impact on the health and safety of the public.
Corrective Actions 1.
FPL will design and implement modifications for the pressurizer pressure instrumentation cabling to resolve the cable separation issue during the next scheduled refueling outage (SLl-17) for St. Lucie Unit 1.
- 2. A temporary change to procedure 1-0NP-100.01, "Response to Fire, " was issued prior to the startup of Unit 1 from the Fall 1999 refueling outage to provide additional means of obtaining pressurizer pressure in the event of an in-containment fire Additional Information NRC FORM 300A I0-'1998)
NRC FORM 366A (6.1898)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION FACILITYNAME(1)
St. Lucie Unit 1 DOCKET NUMBER (2) 05000335 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 1999
005
00 PAGE (3)
Page 6 of 6 TEXT iifmore space is required, use additional copies of IVRC Form 36EAJ (17)
Failed Com onents Identified None Similar. Events The following LERs were submitted for fire protection deficiencies discovered during St. Lucie fire protection self-assessment activities.
1.
LER 50-335/1998-004, "Emergency Lighting Units Not Provided for Alternate Shutdown Access/Egress Routes."
2.
LER 50-335/1998-005, "Conditions Identified Outside Appendix R Design Basis."
3.
LER 50-389/1998-001, "Outside Design Basis Based on Appendix R Safe Shutdown Analysis."
4.
LER 50-389/1998-007, "Appendix R Reverification Identified Potential Cable Failure Modes."
NRC FORM 3BBA (8.1998)