IA-99-106, Discusses Concern Identified During Special Design Architect-Engineer Insp Re EQ of Unit 1 Terry Turbine Woodward Governor Controls for Steam Turbine Driven Auxiliary Feedwater Pump
| ML20205D428 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 08/15/1997 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | Zwolinski J NRC (Affiliation Not Assigned) |
| Shared Package | |
| ML20205C374 | List: |
| References | |
| FOIA-99-106 IA-97-018, IA-97-18, NUDOCS 9904020204 | |
| Download: ML20205D428 (3) | |
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August _15._199L. . - - MEMORANDUM T0: John A. Zwolinski Deputy Director Division of Reactor Projects I/II Office of Nuclear Reactor Regulations FROM: Jon R. Johnson. Director Original signed by Division of Reactor Projects Jon R. Johnson
SUBJECT:
TASK INTERFACE AGREEMENT (TIA 97-018) ST. LUCIE UNIT 1 ENVIRONMENTAL QUALIFICATION (EO) 0F THE WOODWARD GOVERNOR CONTROLS . t During a special Design Architech-Engineer (A/E) Inspection led by the Special { Inspection Branch in NRR (documented in Inspection Report.50-335, 389/96-201). I a concern was identified ~regarding the Environmental Qualification (E0) of the ) linit 1 Terry Turbine Woodward governor controls for the steam Turbine Driven Auxiliary Feedwater Pump (TDAFW). l The Terry Turbine Woodward governor control panel is located in the TDAFW pump
- area underneath the main steam and main feedwater trestle. EQ Documentation <
Package (E0 Doc Pac) 1000. 3 age 1000-3-7 discusses a feedwater or main steam [J high energy line break in t1e steam trestle area. For this break, a steam environment is postulated with a steam temperature of 320 degrees Fahrenheit for a total-duration of 60 to 95 seconds (depending on initial power level) during which time the affected steam generator blows dry. This break would make that area a harsh environment as defined by 10 CFR 50.49 and would , require that the equipment be qualified for its operating environment by l either testing or analysis. The A/E team identified that the licensee. Florida Power and Light Co. (FPL). did not consider the Woodward governor control as part of their E0 program. The licensee classified the equipment as being in a mild environment not within the scope of 10 CFR 50.49 based on the short duration of the exposure and the protection- pro.vided by equipment erclosures. The licensee stated the l temperature increase inside the enclosure will lag the outside temperature due , to insulation provided by the enclosure and the air space internal to the enclosure. The licensee was also trying to retrieve some earlier documentation to demonstrate that though qualification was not required, the Woodward governor control could be qualified for the plant accident condition. The A/E team's interpretation of 10 CFR 50.49 would require environmental qualification of the Terry Turbine Woodward governor control, regardless of any postulated temperature lag. An analysis for temperature lag could be used as part of the qualification analysis but is not sufficient for excluding the equi) ment from environmeital qualification. The environmental qualification
- of t7e Woodward governor controls was identified as unresolved item (URI) 7, 50-335/96-201-05.
k_. 9904020204 990329 T PDR- FOIA
-RALEIQH99 406 PDR g//
J. Zwolinski 2 3 J The iicensee responded to this URI in a letter to the NRC dated May 27. 1997. l In the URI response, the licensee stated that the main steam and auxiliary I feedwater systems were evaluated as part'of NRC Inspection and Enforcement Bulletin (IEB)-79-018. FPL provided a response to IEB 79-01B dated September 30. 1981. The 1981 IEB response indicated that the resultant air temperature spike (from a postulated main steam line break in the steam trestle aret)'would be of very short duration such that the equiament would not in effect experience a harsh environment. The licensee furtler stated in I their response to.this URI that Franklin Research Center (FRC), who served as
-contractor for the NRC to review the IEB 79-01B E0 files, agreed with FPL {
1 regarding the steam trestle area and FRC indicated in their Technical j Evaluation Report dated February 28. 1983, that the equipment in the steam i trestle area was in a " mild" environment and outside the scope of IEB 79-018.
-The licensee also indicated that the NRC provided its concurrence to the FRC Technical Evaluation Report in the NRC Safety Evaluation for Environmental Qualification of Safety Related Electrical Equipment. dated April 21. 1983.
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During a followup to the A/E inspection. Region II inspectors reviewed the St. Lucie Unit 1 EQ Doc Pac 1000. This Doc Pac was designated as drawing number 8770-A-451-1000. St. Lucie Unit 1 Equipment Qualification Documentation i Package. Revision 5. During this revicw the inspectors noted that Section 3.0 of EQ Doc Pac 1000 provided information required to identify properly the j environment to which specific equipment must be qualified. Page 1000-3-1 of EQ Doc Pac 1000 indicated that a harsh environment was limited to three areas
- for Unit 1: the reactor containment building. selected portions of the reactor
/ auxilia'ry building, and the main steam trestle area. This designation would
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require that the Terry Turbine Woodward governor controls, as well as other safety related electrical components located in the steam trestle area, need l to meet the EQ requirements for a harsh environment. The inspectors noted i during this followup inspection that the licensee did not provide adequate documentation to demonstrate that the Terry Turbine Woodward governor controls for the TDAFW pum) were qualified for the harsh environment. The inspectors also questioned w1 ether there was adequate documentation to demonstrate that other safety related electrical components located in the Unit 1 steam trestle area were qualified for the harsh environment. The inspectors further noted during the followup inspection that the Unit 2 steam trestle area (which is designed and configured essentially the same as Unit 1), was designated by the licensee as a harsh environment. The Region II inspectors conclude:I that the licensee's classification of the Unit 1 steam trestie area as a mild environment (in their response to IEB 79-01B) was not consistent with the requirements of 10 CFR 50.49 nor the St. Lucie Unit 1 E0 Doc Pac 1000. Therefore, the Terry Turbine Woodward governor controls. as well as other safety related electrical equi) ment located in the steam trestle area. needed to meet E0 requirements for a larsh environment. Region II requests technical assistance from NRR in the evaluation of this issue. Of particular concern is whether the licensee's classification of the i Unit 1 steam trestle area as a mild environment (based on the short duration ' of the temperature spike) is consistent with the requirements of 10 CFR 50.49.
.Further. if it is determined that the Unit 1 Terry Turbine Woodward governor controls need to meet E0 requirements for a harsh environment. assistance in conducting a backfit analysis is also requested. I i
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J. Zwolinski- 3 ( This. issue was discussed with the St. Lucie project n'anager in NRR/DRPE/PDII-
- 3. the A/E inspection team leader in NRR/ DISP /PSIB. ar.d members from
-NRR/DE/EELB on June 27. 1997. If you have any questions concerning this request contact M. Thomas (404) 562-4631'or H. Christensen.(404) 562-4605.
Docket No: 50-335 License No: DPR-67 Attachments: LA s stated (3) cc w/atts:. C. Hehl. RI-J. Caldwell. RIII' . T. Gwynn RIV K.-Perkins RIV-WCF0 F. Hebdon NRR J. Lieberman. OE . L. Wiens NRR
. JGBarnes'/!RII N
- l orrice pt!.cos ett Des #1f-
/ ett opp .O SIGNATURE g
kvE MThomas:pd HChristensen JJaudon i KLa 4
~DATE 08/f3/97 14 / h / 97 08 / {/97 08_/ l / 97 03 / / 97 08 / / 97
~ COPY? h NO [ YE) NO AY ffES) NO YES NO YES NO OFFICIAL Rf. CORD COPt tax.UMthi NAMt: Un5\L6\iiI.-iTA.tQ j h
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n ttaca m ent i Florida PowGr & Light Company, 6501 South Ocean Drive.Jensen Beac N y 27, 1997 FPL g_g7_13g 10 CFR 50.4 U.'S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, . D. C. 20555- ,,
'97 RE: St. Lucie Units 1 and lW2 -3 A9 :35
' Docket Nos. 50-335/389
, AE' Audit'Open Item Status'
Reference:
NRC Inspection Report'-Nos. 50-335/96-201 and 50-389/96-201 .
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From November 18, 1996 through January 10, 1997, the NRC performed a design' inspection'of the St. Lucie Unit.1 Auxiliary Feed Water
-(AFW) 1 system and- the St. lucie Unit 2 Component Cooling Watef (CCW) system. The- purpose of the inspection was to evaldate the capability of the inspected systems to perform their required design basis functions, to adhere to the design and licensing basis, and to conform to the UFSAR. The inspection results were documented in the above reference.
-Included'in attachment 1 to the inspection report is a listing of inspector follow-up and unresolved items. In response to the NRC report,. attached is the schedule for completion of the corrective
- e. actions planned for the IFIs-and URIs.
Please-contact us if there are any questions about this submittal.
- Very truly yours, y
J. A. ~ Stall ' Vice President St. Lucie Plant . JAS/KWF cc: Region'al Administrator, Region -II, USNRC Senior Resident' Inspector,-USNRC, St. Lucie Plant i Robert M. Gallo, Special Inspection Branch, NRR l l i I t. 1 vi I'
. en FPL Group company 1 N [d[j/7 U -
L-97-139 Attachment Page 1 ( AE AUDIT IFI/URI COMPLETION SCHEDULE / STATUS IFI 50-335/96-201-01 Condensate Storage Tank (CST) Volume Requirements
' Status: 1. The CST volume requirements will be reviewed and the calculations revised as necessary. The current U1 and 2 CST Technical Specification volume requirements will be reviewed, based on the calculations, and a Proposed License Amendment ;
(PLA), if required, will be submitted by December 5, 1997.
- 2. The UFSAR and Design Bases Document (DBD) change packages will be developed to reflect the new calculatior.a and assumptions by. January 31, 1998.
- 3. The Plant procedures and Emergency Operating Procedures (EOPs) will be reviewed and revised to reflect the new calculations by April 30, 1998.
j 50-335/96-201-02 IFI Calculations and Indication for Auxiliary Feed Water (AFW) Flow Status: All calculations and required modifications will be completed by the end of the Fall Unit 1 Cycle 15 Refueling outage. IFI 50-335/96-201-03 AFW Crosstie Net Positive Suction Head Available (NPSHA) Calculation Status: The calculation to document the exact NPSHA for the U1 AFW pumps when taking suction from.the U1 and U2 CST will be completed by September 30, 1997. i IFI 50-335/96-201-04 Calculation Revision for AFW Piping 1 i Supports f Status: 1. The containment check valve testing procedure (1-0700050, Rev. 60) was revised to include testing of AFW check valves every outage. This activity is complete.
- 2. The review of the AFW system piping and supports j will be completed by February 28, 1998. j
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L-97-139 Attachment , Page 2
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URI 50-335/96-201-05 Environmental Qualification (EQ) of Woodward Governor Controls
Background:
The Terry Turbine Governor Control panel is located in the turbine pump area underneath the main steam and feedwater trestle. EQ Documentation Package (Doc Pack) 1000 discusses a feedwater or main steam high energy break in this area. This break would make the area a harsh environment as defined in 10 CFR 50.49 and would require that the equipment be qualified for its operating environment by either testing or analysis. The A/E inspection team determined that 10 CFR 50.49 requires environmental qualification of the Terry Turbine Governor Control. Response: The licensing basis for the EQ qualification requirements of the Terry Turbi'ne Governor Control was researched and documented in Condition Report ' (CR) 97-0046. The Main Steam and Auxiliary Feedwater Systems were evaltated as part of IE Bulletin 79-01B. In the FPL response dated
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September 30, 1981, FPL stated that the steam l trestle was an outdoor area and that when {
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consideration was made of the postulated MSLB and - the size of the equipment vent relief area compared with the compartment volume it would lead ( to the conclusion that the pressure spike would be l dissipated almost immediately. The resultant air temperature spike would be of very short duration such that the equipment would not in effect experience a harsh environment. The Franklin ! Research Center, as contractor for the NRC to l rev.iew the 79-01B EQ files, agreed with FPL and { indicated in their Technical Evaluation Report i dated Feb 28, 1983 that the equipment in the steam ! trestle area was 'in a " mild" environment and { outside the scope of IEB 79-01B. The NRC provided their concurrence in the Safety Evaluation for-Environmental Qualification of Safety-Related Electrical Equipment dated April 21, 1983. Status: This item is complete. IFI 50-335/96-201-06 Full Flow Testing of AFW Crosstie Status: ' 1. The Unit 2 to Unit 1 CST cross connect valves will
<~ be included in the ASME Section XI test program
( and procedures by June 30, 1997.
. Attachment Page 3. '/
1-2. A full flow test of the CST cross tie will be-performed'during the Unit 1 Cycle 15 refueling outage. URI 50-335/96-201-07 Lack of Testing and Operating Procedures for DC Breaker Crossties
Background:
.FPL identified an issue concerning a lack of procedures and testing for switching DC control power to the turbine driven AFW pump during the UFSAR accuracy review. Operating procedures had-not been written to perform a transfer of DC control. power, as necessary to isolate a failed.DC bus or battery. Additionally, the undervo1tage trip feature of the four circuit breakers used to -
complete the transfer of DC power had never been tested. Therefore, the team felt that FPL failed to establish operating and testing procedures as necessary to ensure the operability of the DC bus tie breakers in accordance with 10 CFR 50, Appendix B, Criterion XI. Response: FPL concurs that the above problem statement is essentially correct. However, this condition was (~ self-identified by FPL as part of the UFSAR ( accuracy review. Corrective actions were planned and are being implemented in accordance with CRs 96-2825 and 96-2507, and LER 96-016. { Status: 1. A rotating PM schedule to monitor molded case i circuit breakers for age related degradation was I established and this item is complete. l
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- 2. The 4 Unit 2 DC tie breakers were tested, and 10%
of -the safety related DC molded case circuit
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I breakers were tested during the Unit 2 Cycle 10 refueling outage. This item is complete.
- 3. EOPsil-EOP-02, 1-EOP-06, and 1-EOP-15 will be revised to include directions for performing DC bus realignments by June 30, 1997.
- 4. Surveillance / maintenance schedules for the Unit 1 l and 2 DC cross tie breakers will b,d developed by l September 15, 1997. I
- 5. The 4 Unit 1 DC tie breakers will be tested during the Unit 1 Cycle 15 refueling outage.
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L-97-139 Attachment
, Page 4 l
URI 50-335/96-201-08 Inadequate Troubleshooting Documentation
Background:
The first test of the undervoltage trip feature of the four circuit breakers used to complete the transfer of DC power failed. The original test procedure written for operations to perform the test was well written and received an appropriate 1evel of review. Upon failure of the breaker to function durirg the test, additional testing and troubleshooting were not performed.by procedure, but rather, by scope changes to the original plant work order. Therefore, the team felt that FPL failed to ensure appropriate procedures were used for activities affecting quality in accordance j with 10 CFR 50, Appendix B, Criterion V, and also ! failed to perform testing by written procedures in - accordance with 10 CFR 50, Appendix B, Criterion XI. Response: The original plant work order's scope was changed to allow troubleshooting of the undervoltage device with the breaker installed, vice removed, l from the switchgear. The troubleshooting and testing performed by the plant work order was well within the skill of the craft. Close supervision was provided during all phases of the plant work order. All applicable testing requirements (fr~ example purpose, requirements, acceptance criteria, etc.) were addressed within the scope change, even though-the strict terminology and
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format of a formal test procedure were not used.
.However, a potential weakness was identified in that the troubleshooting instructions could have l concained more' detail to ensure consistent I troobleshooting from shift'to shift.
The disposition to CR 96-2825 documents that the addedi. scope change was within the skill of the craft, and close supervision was provided that reduced the need for greater detail within the plant work order. Therefore, the troubleshooting performed under the work order would not be considered a " step by step" procedure as defined in ADM-0010432, and Facility Review Group (FRG) ! review and Plant General Manager (PGM) approval l was not necessary. However, enhancements to the testing process were made as a result of the review of the work order. A training brief was developed to strengthen expectations for personnel involved in preparing
F-'- . l L-97-139 Attachment ,
, Page 5 I procedural and documentation requirements for i testing performed under the FPL Quality Assurance j (QA) program. l Status: This item is considered complete.
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IFI 50-335/96-201-09 Lack of Tracking for Unidirectional { Drift i Status: FPL reviewed the setpoint program and determined that the Engineering Standard IC-3.17, " Instrument Setpoint Methodology for Nuclear Pow ~er Plants," meets the intent of ISA 67.04-1982, "Setpoints for Nuclear Safety-Related Instrumentation used in Nuclear Power Plants," which is referenced as useful guidance in NRC IN 89-68. Therefore, as documented in CR 97-0037, FPL concludes that no further action is required for this issue. IFI 50-335/96-201-10 Lack of Loop Accuracy Calculations for Indication only Instruments
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Status: Analyses to validate the acceptability of loop
'" accuracies for instruments that are used for indication only will be performed by April 30, 1998.
URI 50-335/96-201-11 Lack of 50.59 Evaluation for Installation of Motor Operated Valve (MOV) Covers
Background:
The team observed that canvas covers had been tied over the top of the AFW pump discharge motor opeiated valves. The concern was that the covers or rope could potentially become entangled in the stem of the valves and compromise the valves' operation. FPL did not have a documented formal engineering evaluation for the covers, nor was a specific installation procedure used. Response: The MOV protective covers were installed as part of the Generic Letter (GL)'89-10 program. The covers were installed in an effort'to protect the MOVs from rain water intrusion to minimize corrosion. In a letter from the NRC to FPL dated June 7, 1994, the NRC documented their approval of the installation of the MOV protective cover, or
" hats," as referred to in the letter.
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However, no specific 50.59 screening or l
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- L-97-139 1 Attachment l Page 6 engineering evalitation was performed for the original installation. The design of the covers, and attachment points, precluded any po i adverse MOVs.
interactions between the covers.ssible and the i Installation of the MOV covers was considered to be within the skill of the craft such that no specific. installation procedure was required. The MOV covers'and installation were screened from 50.59 as documented in CR 96-2870. The MOV covers were subsequently removed from the MOVs due to their age and condition. Re-installation of new covers, if desired,.will require prior Engineering approval. - Status This item is considered complete. IFI. 50-335/96-201-12 Lack of Maintenance Procedure for Changing Panel Filters Status: A maintenance procedure will be developed to
^ inspect / change out the hot shutdown panel filters by July 31, 1997.
IFI 50-389/96-201-01 Camponent Cooling Water (CCW) Perfor ance Curves Status: The revised CCW analysis, stated in-the report to be completed by March 31, 1997 is not done at this time. The analysis will be performed and new performance curves developed by June 30, 1997. IFI '50-389/96-201-02 Operations Night orders for Using CCW Performance Curves ) i Status: The new CCW performance curves will be incorporated into the appropriate operating procedures by August 29, 1997.
'IFI 50-389/96-201-03 Lack of Calculations for'CCW Radiation Monitor Setpoints !
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Status: Setpoint calculations for CCW radiation monitcrs will be performed by March .., 1998. ('- . URI 50-389/96-201-04 Failure to Take Appropriate Corrective e
L-97-139 Attachment
, Page 7 l Actions for Degraded Pen Recorder
Background:
The 2A Emergency Diesel Generator (EDG) tripped on reverse power during a surveillance. A sticking i EDG KW paper chart recorder pen, along with the inexperience of the trainee RCO, contributed to the trip. The team believed the failure to document'and take appropriate corrective actions for the sticking pen recorder lead to mis-operation of the diesel. Response: CR 97-0030 documents the assessment of the effect of the reverse power trip on the EDG. The IDG was not damaged as a result of the protective reverse power trip. Status: The sticking pen recorder was repaired and this item is considered complete. - URI 50-335&389/96-201-01 Failure to Update UFSAR as Required by 10CFR50.71(e) r~
Background:
UFSAR Figure 8.3-14 not representative of the (V battery load' profile and UFSAR Figure 9.2.5 not changed to reflect the 1993 accident analysis I (108 F maximum CCW temperature), I Response: An FSAR Change Package will be developed by 8/31/98 and UFS?.R Figure 8.3-14 revised and i,ncorporated in the subsequent U1 FSAR amendment 16 update. An JSAR Change Package will be developed by 7/31/98 and UFSAR Figure 9.2.5 revised and j incorporated in the subsequent U2 FSAR amendment ; 11 update. . j i. (m
, , , [ga a4%Ne Attachment 2 0 - 8% UNITED ' STATES E ij NUCLEAR REGULATORY COMMISS!ON Q xy j ff WA&HINGTON, D.C. 20555-0001 f
*...+. March 25, 1997
, ..Hr. T. if. L Plunkett - ,
President - Nuclear Division Florida Power and Light Company
. Juno Beach, FL- 33408-0420 l SUBJECT!
ST. LUCIE NUCLEAR PLANTS UNITS 1 AND 2 DESIGN. INSPECTION (NRC
. INSPECTION REPORT NOS. 50-335/96-201 AND 50-389/96-201)
Dear Mr. Plunkett:
During=the period from November 18, 1996 through January 10, 1997 the U.S. Nuclear Regulatory Commission's (NRCs) Office of Nuclear Reactor Regula, tion (NRR) performed a desiga inspection of the St. Lucie Unit 1 Auxiliary . feedwater System '(AFW) and the Unit 2 Component Cooling Water (CCW) System. The purpose of the inspection was to evaluate the. capability of the systems to perform safety functions required by their design basis, adherence to the design and ' licensing basis, and consistency of the as-built configuration with the Updated Final Saftey Analysis Report. The results of this' inspection are contained in the attached inspection report, Overall, the team found the design of the two selected systems to be good, with adequate design margins. Your staff's understanding of the design basis was good, as was their inspection preparation and ability to. resolve (e-~ team identif.ied concerns. The implementation of the design was found to be adequate with some concerns noted. While none of the team's findings resulted in system inoperability, some
.. errors made during the original plant design have reduced system operating margins. Of specific concern are the calculations which support operation of ,
the component cooling, water system. The current calculations.for determining 1
- :the temperature limit for.the seawater intake to the component cooling water j heat exchangers are non-conservative. Your interim actions to' establish a 82 *F temperature limit on intake cooling. water are adequate for the short
. term, but plant operation could be challenged by' higher intake cooling water ,
temperatures that occur during the warmer months of the year. ) A few of.the team's findings were attributed to weaknesses in testing or surveillance activities, including an issue identified by your staff just prior to the inspection concerning a lack of operating procedures and testing of certain safety.related DC circuit breakers. A review of troubleshooting
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. activities related to the above circuit breakers revealed that written l
' documentation.was inadequate to ensure an appropriate level of plant and personnel safety.
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' The team n'oted that your staff has implemented corrective action for many of ,
the specific findings identified in the report. Please provide a schedule, !
- within'60' days of the date of this-letter, for completion of your corrective l actions for the items listed in Attachment 1 to the enclosed report, so that l we can. plan for. re-inspection of these items. ~,
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y. L Mr. T. F. Plunkett - [ ,. As with- all NRC inspections, we expect that you will evaluate the results of this inspection, and where applicable,- apply the specific findings to other systems _and components. In accordance-with 10~CFR 2.790 of the Commission's ce'gulations, a copy of this letter' and _ inspection . report will be placed in the NRC Public Document Room.' - Any enforcement action resulting form this inspection will be issued by-thi NRC' Region II' office via.a separate-correspondence. _Should you have any
. questions co_ncerning the attached inspection report, please contact the'
-inspection team' leader _ Mr. Jeffrey B. Jacobson at (301) 415-2977. ,
Sincerely, d' h Robert-M. Gallo, Chief I Special Inspection Branch 1 Division of Inspection and Support Programs Office of Nuclear Reactor Regulation l
Enclosure:
Inspection Report No. 50-335/96-201 and.50-389/96-20) cc: See next page e n, l
i U.S. NUCLEAR REGULATORY COMMISSION
'0FFICE OF NUCLEAR REACTOR REGULATION Occket Nos.: '50-335 and 50-389 LLicense No.: OPR-67 and NPF-16
' Report No_.: 50-33S/96-201 and 50-389/96-201
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Licensee: Florida Power and Light Company-Facility:
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St. Lucie Nuclear Plants Units I and 2 Location: Jensen Beach, Florida Dates: November .1, 1996 --January 10, 1997 . Inspectors: Jeffrey Jacobson, Team Leader, NRR' Mansoor Sanwarwalla,.Sargent and Lundy - John Ullo, Sargent and Lundy
- Leland Rogers, Sargent and Lundy Richard Jason, Sargent and Lundy Rashmikant Hindia, Sargent and Lundy s
Approved by: Donald P. Norkin, Section Chief Special Inspection Branch DivisionJof Inspection and Support-Programs Office of Nuclear Reactor Regulation I l i 1 s -
r , 1 EXECUTIVE sV MARY During the period from November 18, 1996, through January 10, 1997, the U.S. Nuclear Regulatory Commission's (NRCs) Office.of Nuclear Reactor Regulation (NRR) performed a design inspection of the St. Lucie Unit 1 Auxiliary feedwater System.(AFW) and the Unit 2 Component Cooling Water (CCW) System. The inspection. team was led by an inspection team leader from the Special Inspections Branch within NRR and was comprised of five contractors from Sargent & Lundy Corporation. The purpose of the inspection was to evaluate the' capability of the systems to perform safety functions required by their de'ign s basis, adherence to the-design and licensing basis, and consistency of the as-built configuration with the Updated Final Saftey Analysis Report (UFSAR); The systems were selected for review based upon probablistic risk, previous inspection insights, and modification history. With . regard to the Unit 1 AFW system, the team identified that the operational performance capability was acceptable and the system as installed and operated met both the original design basis and subsequent licensing commitments. In the mechanical review area, the team determined the size of the condensate storage tank, the relief capacity of the atmospheric dump valves and the flow capability of the AFW pumps to be acceptable. Also acceptable was the available net positive suction head for the AFW pumps. The results of the team's electrical review indicated that sufficient voltage and current were available to power the equipment contained within the AFW system. Adequate circuit protection for the electrical equipment was also
,e confirmed. The AFW pump motors were sized sufficiently. ,
I . The team's review of instrumentation and controls identified that the AFW Actuation System setpoints were sufficient to ensure automatic actuation of the AFW system when required. .Also, the condensate storage tank level indication in the control room was-adequate. Walkdowns of the system revealed generally good overall material condition, with some degradation of portions of the governor assembly and inlet supply steam motor operated valve for the AFW turbine driven pump. Notwithstanding the above positive findings, the team identified several issues relative to the system's design or the licensee's implementation of the design. Also, several issues were identified by the licensee during their preparation for the inspection. The following were among the issues identified by either the team or the licensee: i A concern was raised over the acceptability of the technical specification limit for the condensate storage tank level. Although the licensee had in place administrative controls to ensure that an adequate volume of condensate would be maintained to meet all design basis requirements, the current technical specification limit'of 116,000 gallons may not be adequate. 4 i ( _ i
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FP&L has not established environmental qualification for the AFW Terry Turbine Woodward Governor Control. This equipment is in an area that is subject to steam impingement and elevated temperatures for a break in f.- the main steam lines. Preliminary information indicated that the equipment may be qualifiable. FP&L has not included the cross-tie isolation valves which connect the Unit 1 AFW pumps to the Unit 2 condensate storage tank in their ASME Section XI Inservice Test Program. The valves have however been stroked and lubricated on an annual basis. Full flow testing from the Unit 2 l condensate storage tank has not been performed. As part of their generic FSAR review which was ongoing during the inspection, FP&L identified that operational procedures had not been ; written, nor had testing been performed, to confirm the operability of l the circuit breakers used to transfer DC control power from a faulted electrical bus'to an energized bus fo', the turbine driven AFW pump controls. Testing ierformed during the inspection showed the breaker (breakers) were not operational. The documentation related to the troubleshooting of the above circuit j breakers was not adequate. A review of the completed documentation i revealed that changes in the troubleshooting plan were not sufficiently detailed in the work order used to conduct the troubleshooting. Also, the team identified several deficiencies in the specific maintenance test procedures used to perform overcurrent testing of molded case circuit breakers. (, FP&L has not established a program to detect and address unidirectional drift fcr certain AFW instruments. FP&L has not performed an analysis to demonstrate the acceptability of i the ove all loop accuracies for certain instrumentation used solely for ' indication. The turbine driven AFW pump failed a surviellance due to the inability I of the discharge motor operated valve to close. Upon review, the team learned of three other similar failures within the last 16 months. Two of those failures had been attributed to dirty torque switch contacts. Licensee efforts to determine a definitive root cause of the failures have not been successful. - With regard to the Unit 2 CCW system, the team identified that the operational performance capability was acceptable, and the system as installed and operated met both the original design basis and subsequent licensing commitments. In the mechanical review area, the team determined that the CCW system is capable of providing sufficient cooling capacity to cool reactor coolant auxiliary systems components during normal operation, normal plant shutdown, emergency shutdown, and during postulated design bas'is accidents. The available. net positive suction head to the CCW pumps was determined to be acceptable, as was the overall system flow balancing. ii
n d In the electrical area, the team determined that.the batteries were adequately sized, and that acceptable voltage and current are available to powe'r the [-' system loads under all design basis conditions. The CCW pump motor, fuse, and cable sizing were also' reviewed and determined to be acceptable. In the area of. instrumentation and controls, the CCW surge tank level and heat exchanger setpoints were determined to be acceptable. Walkdowns conducted of the CCW system revealed generally good overall material condition. Notwithstanding the above positive findings, the team did identify a few issues'that questioned aspects of the system's design or the licensee's e implementation of the design. Also, some issues were identified by the licensee during their preparation for the inspection. The following were among the issues identified by either the team or the licensee: In preparation for the inspection, the licensee determined that the
-operating curves used to evaluate the maximum allowable sea water temperature for various degrees of fouling of the CCW and intake cooling water heat exchangers were not adequate. The curves were based-on a non-conservative assumption of fouled shutd wn cooling and containment fan cooler heat exchangers. Clean heat exchangers would dissipate more heat and tend to raise the temperature of the CCW system above the 108
*F design limit.
FP&L has not performed formal calculations to support the setpoints for the CCW radiation monitors. Overall based on the above findings, the team found the design of the two selected systems to be good, with adequate design margins. FP&L's understanding of the design basis was good, as was_their inspection preparation and their ability to resolve team identified concerns. The implementation of the design was found to be adequate'with some issues noted, a i i J iii l l
The higher than originally designed flows (see section El.2.2.2) will cause a small velocity increase in the both the AFW pump suction and discharge piping. This system is used for a very small . fraction of plant life, and the small ( increase in velocity is not expected to cause any additional erosion or corrosion problem in the pipes. E1.2.2.4.3 Conclusion The safety-related portion of the AFW system piping meets the requirements of ASME Section III Class B and.C with the exception of the discharge piping up' stream of the outboard containment isolation check valve and the motor-driven pump discharge line. The licensee initiated CR 96-2972 to evaluate the acceptability of this piping and piping supports. The piping itself appears to be acceptable due to adequate. design margins. The check valves used for containment isolation have been leaking. The licensee is revising their existing procedures for testing these valves,to include leak rate testing at every outage, and if the leak is found to be greater than 2 gpm, to refurbish the valves. ! The licensee's actions to evaluate the pump discharge piping and to update the containment check valve testing procedure are identified as Inspector Followup ; Item #50-335/96-201-04. l El.2.2.5 Environmental Qualification
^
El.2.2.5.1 Scope of Review Review environmental qualification of the Terry Turbine Woodward Governor Control to determine that it will perform its safety function in the environment in which it is installed. El.2.2.5.2 Inspection Findings
. The Terry Turbine Woodward Governor Control panel is located in the turbine pump area underneath the main steam and feedwater trestle. EQ Documentation Package 1000, page 1000-3-7 discusses a feedwater or main steam high energy line break in this area. For this break, a steam environment is postulated with a steam temperature of 320*F for a total duration of 60 to 95 seconds (depending on initial power level) during which tna the affected steam J generator blows dry. This break would make that e ,a a harsh environment as defined by 10CFR50.49 and would require that the equipment be qualified for j its operating environment by either testing or analysis. 1 i
The team identified that the licensee has not considered the Woodward Governor I Control as part of their EQ program. The licensee classified the equipment as ; being in a mild environment not within the scope of 10 CFR 50.49 based on the short duration of the exposure and the protection provided by equipment enclosures. The licensee stated the temperature increase inside the enclosure : will lag the outside temperature due to insulation provided by the enclosure l and the air space internal to the enclosure. The licensee was also trying to
< E-18 I l
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y i l l i retrieve some earlier documentation to demonstrate that though qualification ' was not required, the Woodward Governor Control could be qualified for the (' plant accident condition. i El.2.2.5.3 Conclusion
]
The team's interpretation of 10 CFR.50.49 would require environmental qualification of the Terry Turbine Woodward Governor Control, regardless of : any' postulated temperature lag. An analysis for temperature . lag could be used l as part of the qualification analysis, but is not sufficient for excluding the i eg'uipment from environmental -qualification. The licensee has initiated CR 97- J 0046'to address the team's concerns regarding this issue. The environmental 1 qualification of the Woodward Governor Controls is identified as Unresolved l Item # 50-335/96-201,05. . l l El.2.2.6 Cross-tie Connections j 1 El.2.2.6.1 Scope of Review . Review the cross-tie connections for the Unit 2 condensate storage tank to the suction of the Unit 1 AFW pumps. El.2.2.6.2 Inspection Findings Normally closed manual isolation valves are provided to isolate the Unit 2 condensate storage tank from the Unit 1 AFW pumps. These valves are classified as ASME Section III valves and are required to be manually opened to cross-tie the Unit 2 condensate storage tank to the suction of Unit 1 AFW pumps, s I Procedure ON0P.1-0700031, Appendix 0 directs the operator to supply the Unit 1 l MAFW pumps from the Unit 2 condensate storage tank whenever off-normal requirements exists. The Job Performance Qualification requirements (JPM 108-21-06) for operator training require that the isolation valves be opened within 15 minutes after the operator is given the instruction. The isolation valves are ASME Section III valves that are required to operate to perform a safety function. The valves, however, have not been included in the licensee's ASME Section XI Inservice Testing Program. The valves have, however, been stroked and the valve mechanisms re-lubricated on an annual basis. Hence, the valves have been demonstrated to be operable. The licensee was asked to provide test run data, test procedures, or. log book verification to demonstrate that full flow testing had been performed for the cross-tie line with the suction of the Unit 1 AFW pumps tied to the Unit 2 condensate storage tank. The licensee provided flow totalizer indication data in the cross-tie line, but this did not substantiate that full flow testing had been done for the cross-tie line. Consequently, a procedure. change to implement full flow testing of the cross-tie line was initiated by CR 96-2864, i E-19
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s Attachment 3
- 100000-1 i
l 4 e 4 9 ST LUCIE PLANT UNIT NO 1 EQUIPMENT QUALITICATION DOCUMENTATION PACKAGE . 4
, DRAWING NO 8770-A-451-1000 EQUIPMENT QUALIFICATION REPORT AND GUIDEBOOK VOLUME 1 07 1 we 5
. 1000 0 11 k
[' ST LUCIE PIANT UNIT NO 1
\ EQUIPMENT QUALIFICATION DOCUMENTATION PACKAGE DRAVINC NO 8770 A 451-1000 I. APPROVALS AND IDENTIFIERS A. Revision Level and Anerovals ] l l
!E_ Date Revis t en Propered Ey Revfew Anreved By 0 02/12/88 al Revialen R W Walpolo R Geldstein A L schildkraut 1 01/26/40 gegetedPC/M W Jaques W Lewinger A L schildkraus 2 03/06/92 a g ated PC/M W Jeques W Lewinger E J Austin 4 04/20/S2 gegrtedFC/M W Jaques o a Pandya 1 J Austin
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ST Z,UCIE PLA. Y S UNIT NO 1 EQUZPMENT QUALIFICATION DOCUMENTA32CN PACKAG:: DRAWING NO 8770-A-451-1000 TABLE OF CONTENTS - TEXT-SECTION TIT 1E PAGE
. 2.3.4 Margin 1000-2-9 2.3.5 Aging 1000-2-9 2.*3.6 Documentation 1000-2-9 2.4 ~ NUR.EG-0588 1000-2-10 2.4.1 Ganeral -
1000-2-10 2.4.2 Conformance 1000-2-10 2.4.2.1 Selection of Methods 1000-2-10 2.4.2.2 QualificationBy Test 1000-2-12 1 2.4.2.3' Test Sequence 1000-2-14 l' 2.4.2.4 other Qualification Methods .' 1000-2-14 2.5 Ancillary Standards 1000-2-16 l
,. 3.0 Identification of Environmental Conditions 1000-3-1 3.1 Environmental Parameters 1000-3-1 l
. 3.1.1 Operability 1000-3-2 3.1.1.1 General 1000-3-2 3.1.1.2 Environmental Service Conditions '
1000-3 3.1.1.3 Equipment Classification 1000-3-2
-3.1.2 Temperature, Pressure and Humidity 1000-3-3 6
3.1.2.1 General- 1000-3-3
- 3.1.2.2. Normal and Abnormal Temperature Determination 1000-3-4 3.1.2.3 Extended Range 1000-3-4 3.1.3 " Environmental Analysis for High Energy Line Breaks 1000-3-5 Outside Containment 3.1.3.1 Main Steam and Feedwater Systems outside containment 1000-3-5 3.1.3.2 Chemical and Volume Control System 1000-3-9 Outside Containment (Letdown and Chargin8) 3.1.4'- Radiation Environnect
- 1000-3-18 3.1'.4.1 General Description 1000-3-18 3.1.4.2 Source Terms- 1000-3-19 f.
s L._s.
b.g 1000-0.y 4 ST LUCIE PLANT UNIT E EQUIPMENT QUALIFICATION DOCUMENTATION PACKAGE DRAWING WO 8770-A 451-1000
.{
-TABLE OF CONTENTS TEXT SECTION TITLE FAGE 3.1.4.3 Dose Calculations 1000-3-23 3'.1.4.4 Equipment Dose Maps *000-3-25 3.1.5 -Aging Affaces Consideration 1000-3-26 3.1.5.1 Positions on Aging 1000 .? '.5 3.1.5.2 Addit.ional Comments on Aging 1000-3-28 3.1.6 Submerged or Potentially Submerged Equipment 1000-3-29
'3.1.6.1 General 1000-3-29 3.1.6.2 Containment Flood Lavel Analysis 1000-3-29 3.1.6.3 RAB Flood Level Analysis ,' 1000-3-31 3.1.7 Chemical Environment. 1000-3-31 3.1.7.1 Gener'c Chemical Spray concerns 1000-3-31 4.0 Qualification Documentation 1000-4-1 g
1000-4-1 , (, 4.1 Introduction 4.1.1 SQ List 1000-4-1 4.1.2 Documentation Packages 1000-4-la 4.i Margin Application 1000-4-2 4.2.1 General 1000-4-2 4.3 Thermal Lag 1000-4-3 4.4 Arrhenius Vethodo'ogy 1000-4 4 4.5 Alrernate Form of Basic Arrhenius Equation 1000-4 5 4.6 Example of Arrhenius Equation 1000-4-5 4.7 Development of Parametric Analysis of Thermal Agins 1000-4-6 Evaluations Utilizin5 Arrhenius Methodology 4.8 Instrument Accuracy 1000-4-8 4.8.1 General 1000-4-8 I l 4.8.2 Instrument Accuracy Required 1000-4-8 l l I l
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3.0- IDENTIP1 CATION OF ENV2RONMENTAL CONDITIONS 3.1' ENVIRONMENTAL PARAMETERS r ' f. U( ' Section 3 of Documentation Package 1000 provides the information required l to properly identify the environment _ to which specific equipment must be ! qualified. Operability requirements associated with components are l- discussed; the required te nerature, pressure, humidity, radiation, aging and submergence can also be identified. Each parameter is' defined in a specific subsection. Most parameters are
. identified on Zone Maps as a convenient' reference. Zone Maps indicate the normal and abr.ornal values associated with specific areaa the plant at a given period of time. Should more accurate numbers be required, the Zone Map base calculation should be consulted and reviewed as necessary.
Safety related electric equipment may be required to function in either a harsh or a mi.1d environment. Marsh environments are created as a result of the occurrence of a design basis accident, such as a loss of Cociant Accident (LOCA) or Main Steam Line Break (MSLB) inside the containment or MSLB or HELT caid_e the containment. Harsh environments are characterized by abnormally high temperatures and pressures, high radiation doses, corrosive chemical spray, and/or high relative humidity. Also, in some cases, submergence may have to be considered, based on equipment location with respect to maximum flood level. Each of these parameters are discussed at length in the following Subsections. A mild environment, as defined in 10 CFR 50.49, is an environment-that
.* would at no time be eignificantly more severe than the environment that would occur during normal plant operation, including operational
-{ occurrences. Equipment located in a mild environment is not included within the scope of 10 CFR 50.49 and environmental qualification is not required by this program.
Area environments in which radiation is the only parameter of concern are considered to be mild if the total radiation dose (includes 40 year normal dose plus the dose that the equipment will be exposed to post accident) in 1.0E5 rads or less. This value is a threshold for evaluation and consideration. Equipwnt is individually exa_ined based on this screening criteria. Excluded from this consideration, however, are most solid state electronic components'and components utilizing teflon. Class 1E equipment located in radiation environments between 1.0E3 and 1.0E5 racs is' considered on a case-by-case basis to determine if they have any teflon or electronic components that may be affected by these radiation levels. This position-is an extension of the positions taken by the Atomic Industrial Considerations forForum's Nuclear Equipment Industry (Position Qua11fication Paper
- 16) and IPRI on Radiation Sepqrt NP-2129, Radiction Effects on Organic Materials in Nuclear Plantall/ /.
I The Methodology for determining radiatirm levels is addressed in Section 3.1.4. Generally, a harsh envirorment is limited to three areas, the Reantor Containment Building, selected portions of the Reactor Auriliary Building and the Main Steam Trestle. s Specific Harsh Environnent parameters are defined in subsequent sections. 01064/0022q W
T; 1000-3-2 f
. I 3.1.1 Operability j 3.1 1.1 General FSAR Subsection 3.11.1 provides the operability guidelines that were established for environmental qualification. The operability of an item is the duration it'must function post DBA. - Some 10 CFR 50.49 Electrical I Equipment may be designed to only perforn its safety function within a )
short time period into- the event (i.e., within seconds or minutes), and, )
, once its function is complete, subsequent failures are shown not to be detrimental to plant safety. Other +quipment may not be required to perform a safety function but must not fail within a short time period 3 into the event, and subsequent failures are also shown not to be J detr gntal to plant safety.' In conformance with the St Lucie 11 nit 1 )
FSAR '/ Section 3.11.1, however, this equipment should remain functional'in the accident environment for a period of norna11y 15 j minutes. Time margin in excess of the time assumed in the accident ' analysis is not. required by DOR Guidelines unless the DDR testing
- criteria of Sections 2.3.2 and 2.3.3.2 of this report are not met. Time periods less than 15 minutes are acceptable providt.d they can be justified. ,
3.1.1.2 Environmental Service Conditions The plant environment-' rvice con itions are classified in the fo1Aowing environment .asign categories. [ a) 1-A - Long tr.ru contain=ent environment following LOCA or steam line break accident M I Short term containment environment following LOCA or steam line break accident. c) I-C - Containment environment following all other design basis accidents d) I-D - Control room environment following loss of air conditioning The temperature, pressure, humidity, and radiation environment for components are shown on Table 3-1. These parameters should be used unless de 1 tiled calculations are provided to justify less stringent environmental design criteria. 3.1.1.3 Equipment Classification Reactor protective system and engineered safety feature components are classified according to the environmental design categories depending upon their location and functional requirements. Functional requirements are deter =ined by assessing the impact of a safety related. component's failure on the ability to, mitigate the effects of a LOCA or to perform its intended function as part of safe shutdown requirements.
'I
'C 01064/0022q I
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3.1.2 Temperaturo, Prassura and Hunidity 1 3.1.2.1 General i- Heating, ventilatien and air conditioning (HVAC) syste=a are provided to f l naictain suitable operating anbient conditions for all electrical, l Instrumentation and nechanical systens. The design basis and design description of HVAC systens are found in the St Lucie Unit 1 FSAR Section 9.4. Table 3-1 presents the representative Environnental Qualification temperature profile for equipment located in harsh environments in the ! plant. j i Specific featuras and the design bases for environmental parameters such as service anblents, and high energy pipe break induced severe environments are described in Subsection 3.1.3 of this report.
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( l i l l j i 0106q/0022q
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.3.1.2.2 Normal and Abnormal Temperature Deter::iination For tha purposa of cnvironmsntal qunlification, conservatism was utilized in the determination of non-DEA temperatures.
The design basis per the ASHRAE conservative standards is based on the wet bulb and dry bulb readings for all but 1% of the time during the summer months (30 hours) which is 93*F Dry Bulb (FSAR Section 9.4). The 30 hour time period above the 93'T temperature has been assumed to equal the highest temperature on record which is 201'F for the full time period. As the temperature in the containment is dependent on plant operation rather than outside ambier.t, a review of plant availability and time at shutdown can provide the true normal ivr design life aging in the, plant. Normal containment temperature is defined in accordance with the I following: Average * [(FPT) x (A)) + [(1-A) x (SI)], where FPT = Full Power ST = Shutdown A = Plant - Temperature Temperature Availability Normally temperatures inside the Reactor Auxiliary Building are specified at 104*F and for the Reactor Containment Building the normal temperature is 120*F. Actual calculated temperatures for specific areas can be obtained from Table 3-1.
,, 3.1.2.3 Extended Range Accident Monitoring Instrumentation
/
Extended range'(beyond the Design Basis Accident) Accident Monitoring { . Instrumentation is being added to St Lucie Unit 1 in accordance with a commitment to NUREG-0737 (FSAR Subsection 7.5.3 TMI Related Additional Accident Monitoring Instrumentation) and RG 1.97 Revision 3. There is no requirement for margin for these instruments in accordance with NUREG-0737 Appendix b. The containment wide range pressure cenitors are provided with a range of
-5 psig to 175 psig. The containment sump level indication will indicate water levels up to 600,000 gallons.
l l [ 0106q/0022q i
3.1.3 Environe ntal !.nalysis for High Enngy Line Breaks - Outsida Contain=3nt
- The St Lucie Unit 1.high energy piping systems are designed, specified, I
[
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fabricated, analyzed and install ' to the quality standards as indicated in the FSAR to assure that a high rsy line break (HELB) is extremely l
-unlikely. HELBs, however, are analyw
- r.nd are described in Section 3.6 l
of the FSAR. Additional margin or conservatism is inherent as no credit is taken in the HELB analysis for flow attenuation whicn begins immediately upon the isolation valve closing stroke (i.e., a conservative assumption is made that full flow remains until isolation valves are closed). The High Energy Piping Systems (i.e., fluid systems which exceed 200*F and/or 275 psig during normal operating conditions) that are considered for pipe rupture analysis outside containment are: a) Main Steam (MS) and Feedwater (FW) Systems b) Chemical and Volume Control System-(Charging and Letdown) . c )' Steam Generator Blowdown System (SGBS) 1 d) Auxiliary Steam System (ASS) - e) Auxiliary Feedwater System (AFW) The criteria used to locate the break points for high energy P pingi ! outside containment are described in FSAR Appendices 30 and 3D. I r 1 i \
;( Consistent with the " systems analysis methods" of IEB'79-013 and the '
comment resolution to comment 41 of NUREG-0588 Revision 1, not all equipment subject to HELB outside containment need be qualified for the . HELB event. In fact, the great majority of safety related equipment ) outside containment need not be qualified for HELB. The equipnent which l reyJires qualification is equipment whose failure ';2sulting from the HED l will be detrimental to mitigation of the HELB or detrimental to plant shutdown if required following the HELB. Equipment items providing an isolation function far the HILB events may be outside the area of influence; consequently, these items vould not be i induded in the harsh environment Component Evaluation Sheets. 3.1.3.1 Main Steam and Feedwater Syste 2 Outside containment 3.1.3.1.1 Introduction In analyzing a main steam or feedwater line break outside containment, particular attention is expended in determining the effects on safety related equipment. 1 i 0106q/0022q m M
'Tbn main stacc and feedwater lines for each St Lucie Unit are routed from the containt..mt building to the turbins building via two saismic Class I trestles (each trestle supports a main stean line and its corresponding f feedwater line). Once outside the containment building, there is no I other enclosure through which the lines pass on route to the turbine building.
The main steam lines are separated by approximately 13 ft as they emerge from the containment and diverge such that at the main steam line isolation. valves the lines are approximately 40 ft apart. The only other safety related components in the area are the three l auxiliary feedwater pumps and motors which are locrted under the ] trestles. The two motor driven auxiliary feedvater pumps are located under.one trestle and the steam turbine driven pump is located under the l other trestle. I 3.1.3.1.2 Analysis The'fo11owing analysis is based on the AEC issued " General Information l Required for Consideration of the Effects of a Piping System Break , J Outside Containment." j
- 1) Protection against pipe whip has been provided outside containment for the main steam and main feedwater systems based on the following )
criteria { a) Maximum operating p-essure and temperature for the main steam (MS) system is 885 psig and 520*P respectively; ciaximum I operating pressure and temperature for the main feedwater (TW) ! [_ q system is 1050 psig and 440*F respectively. b) The auxiliary feedwater syste= pumps (1 steam turbine driven pumps and 2 electric motor driven pumps) are located under the seismic Class I trestles that support the MS and FW piping on route from the containment to the turbine bu'.1 ding.-
- 2) The main steam and feedwater lines for steam generators 1A and 13 are run on separate seismic Class I trestles. The two steam lines are separated by a distance of 15 ft as they emerge from the containment and by a distance of 40 ft at the riser where they turn to enter the turbine building. The feedwater lines are run at a distance of 15' 7" from their respective steam lines and are located approximately 60 f t from each other at the entrance to the containment. Refer to Figures 3-1 and 3-2.
All of the above lines have restraints which are designed to , restrict motion normal to the axes of the MS r.nd FW lines. The lines, therefore, will not whip against each other and in no case will the impingement pressure generated by a rupture of a line on trestle A affect the lines on trestle B. For instance, the maximum impingement pressure which steam line A could transmit to its counterpart on trestle B is 15 psia. The resulting stresses are within design values for a faulted condition. ( k
' 0106q/0022q
r The only ssfoty related cquipoint that could ba affected by a rupture in the MS or W lines are the three auxiliery fatdwnter
, pumps and their associated valves and controls (2 motor driven, 1
, steam driven) which are located under the trestles. The two
' . electric motor ' driven pumps are located approximately 15 f t f rom each other under one trestle and the steam turbine driven pump is located under the other trestle. The exact orientation of the MS and FW lines and the auxiliary feedvater pumps can be seen on ,
Figures 3-1 and 3-2. Atsuming a rupture in a main steam line and assuming an adiabatic expansion of the escaping steam, the temperature of the steam will decrease to approximately 320*? upon release from the steam line. This situation can be assumed to exist for a total of 60 to 95 seconds (depending on initial power level) during which time the effected steam generator blows dry. A loss of normal feedwater is assumed since this is the only condition which would require the use of the auxiliary feedwater system. The maximum temperatures will only be experienced by the pump towards which the jet is directed. The equipment manufacturers for the pu=ps and pump motors have stated that their equipment can function in the ensuing environment described above with the only possible ill effects being the failure 1 1 of pump seals due to the ta=perature. 'Ihis type of failure could
- result in the loss of a maximum of 5 to 10 spm but no loss of function.
There is also no danger that a rupture of a steam line or feedwater line could cause a loss of function of more than one auxiliary Each of the three pumps are ( feedwater pump due to flooding. provided with a flood wall around them to elevation +22 ft. Under normal conditions, with no hurricane flood warnings issued, the stop logs are ror in place in the flood wall and accumulation within the enclosure is impossible since the condensed steam vill run out over plant grade. l
- There is.no other credible postulation of interaction between a ruptured main steam line and any connected branch line that could lead to a more detrimental condition than that described above or otherwise affect the plant capability for safe shutdown.
- 3) A steam line or feedwater line break will not directly or indirectly result in loss of redundancy of any portiou of the protection syste:
(as defined in IEEE-279), class 1E electric system (as defined in IEEE-308), engineered safety feature equipment, cable penetrations, or their interconnecting cables required to mitigate the consequences of the accident ard pisce the reactor in a cold shutdown condition. 0106q/0022q
A Some safety reacted enbles that will sxperience a change in pressure
- and tamp;rstura conditions ara thess associated with thn auxiliary i feedwater system. All cable in the trestle area is routed through underground or above ground conduit which will act as a shield from
( the effects of a pipe rupture accident. The cables are fully enclosed and'are thermally rated for a temperature of 90*C which is below the steam escape te=perature of 320*F. Note, however, that the 320*F temperature is predicated on an adia h tic expansion, the duration of which is between 60 and 95 seconds, and that the extreme temperature will only be experienced by the pump towards which the slot break (equivalent in area to cross-sectional area of pipe) jet is directed. It is expected that the cables' associated with the I
- impinged upon pump will suffer no adverse effects causing loss of j function. Even if one pump is renc ered inoperable, the two 8
recaining auxiliary feedvater pumps have sufficient capacity to allow reactor cooldown'to 300*F. Other electrical equipment expected to remain operable after the accident are the main steam isolation valves, the atmospheric dump valve and the steam line safety relief valves of the intact main steam line. The maximum expected impingenent pressure on any conduit on the intact trestle is 15 psia. ,
- 4) The north wall of the control room is approximately 100 it from the closest main steam line and approximately 85 ft from the closest feedwater line. Since both the MS and FW lines are located outside in the plant yard, no appreciable te=perature buildup is anticipated. Newever, redundant control room air intakes are '
,- provided on t M uorth and south walls of the reactor auxiliary l
building. In the event that a temperature buildup occurs, air intake to the control room can be effected through the south wall intake. Another alternative would be to c1cse both air intakes and run the ventilation system in the recirculation mode for as long as is necessary.
- 5) The safety related electrical equipment which could experience changes in temperature and pressure due to a pipe rupture accident are listed below:
a) The motors of auxiliary feedwater pumps 1A and 1B and the motor operated valves and controls b) The motor driven steam stop valve, I-Mi-08-3, for the turbine i driven auxiliary feedwater pu=p 1C l c) The actuating circuitry of the main steam isolstion valve (and ) . seat bypass valve) of the intact system The manufacturers of the equipment listad above have stated that j there should be no degradation of equipnent due to the environment { j postulated to exist af ter a main steam or feedwater line rupture. All of the above listed equipment is designed for outdoor service I and is expected to withstand the relatively short 11 veri. temperature i transient resulting from a main steam or feedwater line rupture. i All cables routed to this equipment are coupletely enclosed by l \ !
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0106q/0022q
7 7 conduit and are rated for 90*C service. There will bs no loss of system function if one auxiliary feedwater pump becomas inoperable; there will be no loss of syste= function if the motor driven steam f stop valve (I-MV-08-3) becomes inoperable; and, there will be no ( ' loss of isolation function on the intact main steam line since the 1 1 valve is designed to fail closed on loss of power. Safety related features of the plant, other than those identified above, will not be affected by a main steam or feedwater line break since the propensity for damage is attentuered with distence and no additional safety related equipment is located in the area.
- 6) ~Since the main steam and feedwater system piping is not routed through any enclosed areas after emerging from the containment i structure, buildup of pressure in thu e areas is not anticipated. j In a similar manner, the only tempecature buildup expected will be ;
in the immediate area of the ruptured line and along the path of its l resultant jet. Based on an adiabatic expansion of the stene line j fluid, a very conservative jet temperature of 320*F is assumed for the duration of the blowdown (95 seconds) at a prersure of IS psia. The conservatism is canifest ainee no mixing or heat dissipation is considered in the sasumption. Assumptions, methods, and'results of analyses concerning the steam generator blowdown is presented in Section 15.4.6 of the-St Lucie Ualt 1 FSAR. 3.1.3.2 Chemical and Volume control System outside containment (Letdown and
- Charging Line)
( 3.1.3.2.1 Ceneral Description i The systems analyzed herein are the lines for shutdown cooling which i includes portions of the low pressure safety injection system, chemical volume and control system (letdown and charging lines), steam generator blowdown system and auxiliary steam systec. ; In analyzing the effects of rupture in these high energy lines on systems or components required for safe shutdown, except as noted hereinafter, the following general criteria were considered: a) For those concrete structures protecting systems and components , essential for safe shutdown, the load combination of pipe rupture ' and design basis earthquake (DBE) is assumed. b) Single active failure in addition to the pipe rupture is assumed. c) Other than normal shutdown systems (e.g., ECCS) are considered acceptable to achieve safe shutdown. d) Piping which is pressurized only during testing is not considered. e) The criterion used to demonstrate structural adequacy is to show no loss of function. 0106q/0022q ) l j l __}}