Text

Clarification to NRC Commitment Regarding Generic Letter 89-13
	ML13025A208
Person / Time
Site:	Saint Lucie
Issue date:	01/10/2013
From:	Jensen J; Florida Power & Light Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	GL-89-013, L-2013-005
	Download: ML13025A208 (10)
	v • d • e

0 January 10, 2013 FPL.

L-2013-005 10 CFR 50.4 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 Re: St. Lucie Units I and 2 Docket Nos. 50-335 and 50-389 Clarification to NRC Commitment Regarding Generic Letter 89-13

References:

1. FPL Letter L-2000-215 dated November 9, 2000, "NRC Commitment Change Generic Letter 89-13" Reference 1 detailed the justification used by Florida Power & Light (FPL) to change the original NRC Generic Letter 89-10 commitment regarding service water inspection frequencies.

Based on existing inspection results and the service water inspection program, FPL changed the inspection interval for the intake cooling water (ICW) systems from 100% every outage to a single train inspection each outage.

During the last Unit 1 refueling outage (SL 1-24) ICW piping inspections and repairs, FPL determined that the original inspection frequency justification did not explicitly address two segments of pipilng that were epoxy lined rather than cement lined. FPL updated the previous justification to reflect the epoxy lined piping segments present in the Unit 1 ICW system piping and the update is contained in the attachment to this letter. This clarification has no effect on FPL's current practice of performing single train ICW piping inspections each outage at St.

Lucie.

Very truly yours, Site Vice President St. Lucie Plant Attachment JJ/KWF Florida Power & Ught Company 6501 S. Ocean Drive, Jensen Beach, FL 34957

St. Lucie Units 1 and 2 L-2013-005 Docket Nos. 50-335 and 50-389 Attachment Page 1 EVALUATION OF THE ACCEPTABILITY OF SINGLE TRAIN INTAKE COOLING WATER (ICW) INSPECTION

SUMMARY

This evaluation provides the bases for a change in the frequency of the routine internal inspection interval for the St. Lucie Units 1 and 2 safety-related intake cooling water (ICW) piping. The change in frequency is from 100% (double train inspection) every outage to approximately 50% (single train inspection) during each outage (starting with the spring 2001 Unit 1 refueling outage (SL1-17)) resulting in 100% inspection every other outage.

FPL responses to NRC Generic Letter (GL) 89-13 recommended actions 2, 4, and 5 are not changed by this evaluation. Recommendations 1 and 3 will be changed for inspection of the safety-related ICW piping from 100% every outage to single train each outage resulting in 100% every other outage starting with SL1-17. Changing the inspection frequency will result in changes made to commitments made to the NRC via Reference 39.

This evaluation documents the acceptability of the revised commitments with respect to NRC guidance provided in GL 89-13 (Reference 5).

This supplement provides clarification regarding the lining material originally installed in two segments (CW-29 and CW-30) of ICW piping on Unit 1 and addresses repairs performed on these two segments during the SL1-24 refueling outage. Revised sections are marked by a revision bar in the right hand margin.

The ICW system is outside of the primary containment and inadequate performance of the ICW piping liner could adversely affect the orderly and safe shutdown of the plant.

Therefore, the ICW piping liner is considered to be Service Level III as defined by EPRI TR-109937, Guideline on Nuclear Safety-Related Coatings (Reference 37). The ICW piping liner was installed prior to the issuance of Reference 37; however, special process controls are used during the installation of repair materials which are in compliance with the EPRI guidelines. The EPRI guideline is referenced in Regulatory Guide 1.54 (Reference 38), and is considered an industry guideline for coatings both inside and outside of containment.

EPRI guidance for the inspection of coatings is found in Reference 37, Section 8 Condition Assessment. Table 8-1 recommends that the condition of service water systems (e.g.,

ICV) be assessed once every three to five years.

A review of ICW inspection reports (references 6 to 28) was performed to provide the basis for increasing the inspection interval. These inspection reports cover a time span of 15 years from 1986 to 2000. A review of the station's ICW inspection reports for the years from 2001 through November, 2011 provides corroborating data. The inspection reports for CW29 and CW-30 during refueling outage SL1-24 are addressed in this supplement. The three general areas of inspection are intake, cross yard, and CCW heat exchanger. A review of the data indicates that there has been evidence of some liner damage associated with corrosion cells identified in these areas. However, the enhancement of system components and application of better protective coatings have proved to be effective

St. Lucie Units 1 and 2 L-201 3-005 Docket Nos. 50-335 and 50-389 Attachment Page 2 (trending down) in retarding corrosion in areas of dissimilar materials contact, flange faces, valve bodies, annular spaces between flanges, and small bore branch connections.

Corrosion experienced during longer inspection intervals would be confined to individual small areas of wall thinning rather than general pipe wall thinning and would not create any structural concerns.

ICW internal piping biofouling (marine growth) continues to be minimal and consistent between outages with minor or no growth in the ICW intake piping and component cooling water (CCW) heat exchanger area piping. The short piping stagnant connections (cross-tying the A-C and B-C ICW pumps and the A-B CCW heat exchangers) promote minor silting and marine growth that has remained consistent between outages. The marine growth present in the underground portion of the ICW piping during the last three inspection cycles on Unit 1 and Unit 2 continues to be consistent at one half to one inch. Biofouling during longer inspection intervals would not create any flow blockage concerns in these areas.

Intake well biofouling was measured and video taped (reference 40) during the Unit 2 spring 2000 refueling outage (SL2-12). The marine growth was two inches thick at the traveling screens to approximately four inches thick at the circulating water pumps (the ICW pumps are located between the circulating water pumps and the traveling screens).

Dislodgment of marine growth usually occurs when the buildup is greater than four inches and would preferentially flow into the circulating water system due to the higher flow rate.

During design basis accident (DBA) conditions, the flow rate in the intake well is reduced by a factor of approximately 10 that would retard dislodgment and flow into the ICW system.

Biofouling expected during longer inspection intervals would not create any flow blockage concerns in these areas.

Increasing the individual train inspection interval from every outage to every other outage is consistent with the guidance criteria set forth in EPRI TR-109937 and will not have a significant impact on the reliability or functional capabilities of the ICW system.

The ICW system piping material are carbon steel (e.g. Pipe is ASTM/ASME AISA 106 Grade B, elbows are AISA234 Grade WPB and flanges are AISA105) with cement mortar internal lining, except for piping segments CW-30 (A Train) and CW-29 (B Train) on Unit 1.

These two segments were internally coated with coal tar epoxy prior to unit startup.

Butterfly valves are carbon steel body with rubber and/or epoxy lining and stainless steel disc or stainless steel body and stainless steel disc. Expansion joints are rubber (SL-1) or stainless steel (SL-2). Piping spools downstream of valves TCV-14A & B are stainless steel.

ICW SYSTEM SAFETY-RELATED FUNCTION

1. The ICW system shall provide an adequate heat sink for the CCW system during DBA conditions to support all required CCW heat removal functions assuming a single failure concurrent with a loss of off-site power (LOOP).

St. Lucie Units 1 and 2 L-2013-005 Docket Nos. 50-335 and 50-389 Attachment Page 3

2. The 1CW system shall provide an adequate heat sink for the CCW system to allow the reactor to be brought to cold shutdown from the'control room in the event of a LOOP and assuming the most limiting single failure.

BACKGROUND GL 89-13 required licensees to provide information about plant service water systems to assure the NRC of compliance with 10 CFR Part 50 Appendix A, General Design Criteria (GDC) 44, 45, and 46), and 10 CFR Part 50 Appendix B Criterion Xl, and to confirm that the safety functions of service water systems are being met. The GL included five specific recommendations. By letter L-90-28 dated January 25, 1990, FPL provided the response to each of the five recommended actions.

FPL's response to recommended actions 1 and 3, as provided in L-90-28, are as follows:

Recommended Action I For open cycle service water systems, implement an ongoing program of surveillance and control techniques to significantlyreduce the incidence of flow blockage problems as a result of biofouling.

FPL Response St Lucie Plant presently follows the NRC recommended program to resolve Generic Issue 51, Proposed Requirements for Improving the reliability of Open-Cycle Service Water Systems, which includes inspecting the intake structure and piping for macroscopic biofouling every refueling outage, cleaningif necessary,and chlorinatingthe system up to the limits allowed by environmental laws.

Recommended Action 3 Ensure by establishing a routine inspection and maintenance program for open-cycle services water piping and components that corrosion, erosion, protective coating failure, silting and biofouling cannot degrade the performance of the safety-relatedsystems supplied by service water.

FPL Response St Lucie currentlyhas a program thatperforms a 100% inspection of the ICW system piping and components. As found conditions are documented and repairsmade as required. This program is implemented on both Unit 1 and Unit 2.

St. Lucie Units I and 2 L-2013-005 Docket Nos. 50-335 and 50-389 Attachment Page 4 EVALUATION Degqradation Mechanisms Carbon steel pipe used to transport seawater is exposed to the effects of corrosion. This exposure and subsequent corrosion is dependent on several varying parameters. The three predominant parameters that affect the rate of corrosion are temperature, flow rate, and pH. The relative acidity of the solution is the most important factor to be considered.

At low pH, the evolution of hydrogen tends to eliminate the possibility of protective film formation so the steel continues to corrode. In alkaline solutions, the formation of protective films greatly reduces the corrosion rate. The greater the alkalinity, the slower the corrosive attack rate.

The cement lining creates a corrosion inhibiting alkaline environment (pH=12) at the surface of the steel. Hairline cracks (most less than one thirty-second of an inch wide),

small shrinkage cracks, and small gaps between the lining and the pipe are usually not a concern since the alkalinity stifles corrosion of the base material. Cement lining at flanged connections does not include the flange face and a crevice is created at this interface.

Intrusion of seawater in this crevice can result in crevice corrosion. Dislodgment of a portion of the cement lining due to impact damage or erosion of exposed edges can lead to local corrosion spots due to the galvanic effect between the exposed carbon steel base material and alkaline environment under the lining.

The two piping segments on Unit 1 (CW-29 and CW-30) which were originally installed without cement lining on the inside diameter had been coated with coal tar epoxy. The service life of coal tar epoxy in saltwater immersion can vary from 14 to 21 years (Reference 42, pg. 29). End of service life is characterized by embrittlement, cracking and peeling. The effect of liner damage is evidenced by localized (crevice and pitting) and galvanic (electrical contact with a more noble metal) corrosion. Biofouling in the intake well and/or the internal portion of the ICW piping could impede the flow of water to the CCW heat exchangers.

Inspection Techniques / System Enhancements Inspection methods include systematic planned crawl through inspections of the ICW system, which are conducted during refueling outages. FPL personnel and qualified subcontractors perform the internal inspections to determine the existing condition and recommend repairs. A detailed report that includes findings, repairs, photographs, and comments is developed.

Removal of the corrosion products (including weld repair, when required) and the application of non-metallic protective barriers such as epoxy (e.g. Duromar, Belzona, and Fusor) correct areas of identified corrosion. Biofouling is observed, measured, and removed as determined necessary.

St. Lucie Units I and 2 L-2013-005 Docket Nos. 50-335 and 50-389 Attachment Page 5 Enhancements to ICW system components have been implemented to retard the effects of corrosion as follows:

1. replacing rubber lined carbon steel valve bodies with stainless steel valve bodies or internal epoxy coatings,

2. applying an epoxy coating to interior surfaces of stainless steel piping and valves to reduce galvanic effects,

3. repairing flanges by weld repair, by applying a nonmetallic filler, and applying a zinc-rich coating to flange faces and,

4. sealing of crevices.

A review of ICW piping inspection reports (references 6 to 28) was performed to provide the basis for increasing the inspection interval. These inspection reports cover a time span of 15 years from 1986 to 2000. A review of the station's ICW inspection reports for the years from 2001 through November 2011 provides corroborating data. The three general areas of inspection are the intake piping, cross-yard piping, and the CCW heat exchanger.

This data for the cement lined segments of ICW piping indicates that, although there has been evidence of some liner damage with corrosion cells identified in these areas, the enhancement of system components and application of better protective coatings have proved to be effective in retarding corrosion. Specific improvements have been implemented in the areas of dissimilar materials contact, flange faces, valve bodies, annular space between flanges, and small bore branch connections. Corrosion expected to occur during longer inspection intervals should be confined to small individual areas of wall thinning rather than general pipe wall thinning and should not create any structural concerns.

ICW piping segments CW-30 and CW-29, epoxy coated on the ID on Unit 1, run underground in parallel for approximately 200 feet from downstream of the CCW Heat Exchangers and downstream of the restriction orifices to the discharge canal. Each segment is approximately 17% of the total length of each lCW train. The last -60 feet of each pipe run remained submerged in saltwater during refueling outages and inspections are normally performed by divers. This piping has been reduced to -40' during pipe replacement. Anticipated corrosion would also be expected to be confined to localized areas of wall thinning rather than general pipe wall thinning.

Biofoulingq ICW piping internal biofouling continues to be minimal and consistent between outages with minor or no growth in the ICW intake piping and CCW heat exchanger area piping. The short cross-tie stagnate connections (cross-tying the A-C and B-C ICW pumps and A-B CCW heat exchangers) in the ICW piping have experienced minor silting and marine growth between outages. The marine growth present in the underground portion of the ICW piping during the last three inspection cycles on Unit 1 and Unit 2 continue to be consistent at one half to one inch thick. Anticipated biofouling during longer inspection intervals would not create any flow blockage concerns in these areas.

St. Lucie Units I and 2 L-2013-005 Docket Nos. 50-335 and 50-389 Attachment Page 6 Intake well biofouling was measured and video taped (reference 40) during the Unit 2 spring 2000 refueling outage (SL2-12). The marine growth varied from two inches thick at the traveling screens to approximately four inches thick at the circulating water pumps (ICW pumps take suction in between the circulating water pumps and the traveling screens).

Since the intake wells on both units are similar, and are cleaned during refueling outages, the amount of growth observed is considered typical between refueling outages for both units. Marine growth dislodgment usually occurs when the buildup is greater than four inches thick. Any marine growth dislodgment should preferentially flow into the circulating water system due to the higher flow rate. During DBA conditions, the flow rate in the intake well is reduced by approximately a factor of 10 that would retard dislodgment and flow into the ICW system. A review of the differential pressure (DP) trend data across the CCW heat exchanger during plant operations suggests that DP may be influenced in the last half of the refueling cycle by biofouling dislodgment in the intake well. This could result in an additional heat exchanger cleaning during the 18-month extended period between intake well cleaning. However, anticipated biofouling during longer inspection intervals would not create any flow blockage concerns in these areas.

Chlorinating the intake wells has proved effective in maintaining the biofouling in the ICW piping consistent during the last several outages.

Basis of the Revised Augmented Inspection Schedule The ICW system is outside of the primary containment and inadequate performance of the ICW piping liner could adversely affect the orderly and safe shutdown of the plant.

Therefore, the ICW internal liner is considered to be Service Level III as defined by EPRI TR-109937, Guideline on Nuclear Safety-Related Coatings (Reference 37). The ICW piping liner was installed prior to the issuance of Reference 37; however, special process controls are used during the installation of repair materials which are in compliance with the EPRI Guidelines. The EPRI guideline is referenced in Regulatory Guide 1.54 (Reference 38), and is considered an industry guideline for coatings both inside and outside of containment.

EPRI guidance for the inspection of coatings is found in Reference 37, Section 8 Condition Assessment. Table 8-1 recommends that the condition of service water systems (e.g.,

ICW) be assessed once every three to five years. It is also stated within the guideline that:

"...once initial inspections have been conducted, then the inspection scopes can be adjusted based on an analysis of the findings. Should inspections indicate satisfactory conditions, then frequencies of future inspections may be adjusted accordingly."

The Unit 1 ICW system was drained in 1999 and the Unit 2 ICW was drained in 2000 for the inspection of the ICW piping liner. FPL performed a hands-on inspection of the internal liner at those times. The liners were inspected for acceptability of the following properties:

St. Lucie Units 1 and 2 L-2013-005 Docket Nos. 50-335 and 50-389 Attachment Page 7 delamination, adhesion, peeling, flaking, undercutting, blistering, cracking, checking, and holidays.

At the close of the last Unit 1 and Unit 2 refueling outage inspections, SL1-16 and SL2-12 respectively, the liners met the acceptance criteria for all of the properties listed and areas of degradation were repaired.

Any problems associated with this type of pipe/liner would most probably be associated with delamination or loss of adhesion resulting in localized (crevice, pitting, or galvanic) corrosion. This condition would likely be accompanied by cracking of the liner, and (if present) would most likely have been discovered during inspection since local corrosion areas are readily visible during inspection. The liners have been inspected during refueling outages since original installation, with a trend toward fewer repairs in the areas of flange faces and valve liners. The majority of the indications are minor in nature without a major reduction in base material. The abnormalities discovered during inspection would not have challenged the safety-related function of the system.

CONCLUSION Based the good performance of the liner and repair material as verified through inspections performed to date, FPL plans to adjust the inspection schedule. The revised inspection schedule requires a hands-on inspection of the intake well and ICW liner once every other outage (approximately once every three years), beginning with SL1-17. This is considered acceptable for the following reasons:

" the material used for the liner and valve repair, as verified through engineering review

" the historical performance of the liner

" the results of the inspections performed to date

" ultrasonic (UT) examinations of selected lining repair areas identified performed to provide evidence of adequate wall thickness based on Reference 25 criteria

" sufficient margin in the design to allow for minor leaks in the ICW system (Reference 34 and 35)

the marine growth present in the underground portion of the ICW piping has remained consistent at one half inch to one inch for the last three inspection cycles

" dislodgment of marine growth in the intake well during longer inspection intervals not creating any flow blockage concerns.

Coal tar epoxy lined ICW piping segments CW-30 and CW-29 on Unit 1 run underground in parallel for approximately 200 feet from downstream of the discharge of the CCW Heat Exchangers and downstream of the restriction orifices to the discharge canal. Each segment is approximately 17% of the total length of each ICW train. The last -60 feet of each pipe run remained submerged in saltwater during refueling outages and inspections are normally performed by divers. This submerged piping has been reduced to -40' during

St. Lucie Units 1 and 2 L-201 3-005 Docket Nos. 50-335 and 50-389 Attachment Page 8 pipe replacement. During the SL1 -24 refueling outage inspections performed in December 2011 and January 2012, degraded localized corrosion was found in about a 10 foot section of piping in each train, starting approximately 30 feet from the discharge end of the pipe.

Several through wall holes were identified in each train. It was decided to replace the submerged section of both pipe segments. Functionality of the in-service train was determined and new piping, top coated with Plasite 4550, was installed. A detailed Root Cause Evaluation (Reference 42) was performed and Corrective Actions to Prevent Recurrence were developed. Two Root Causes were identified, as follows: 1) failed coal tar epoxy that exceeded its service life, and 2) dive inspection did not allow suitable inspection conditions to detect coating degradation. The Corrective Actions that are being implemented to provide a more robust ICW piping inspection program, consistent with EPRI TR-1 09937 guidelines (Reference 37) which have been updated and are encompassed in the latest EPRI Report 1019157 (Reference 41).

Changing the inspection interval for the ICW system from 100% every outage to a single train inspection each outages will not impact the operability or integrity of the ICW system.

REFERENCES

1. Unit 1 UFSAR, Amendment 17

2. Unit 1 Technical Specifications, Amendment 164

3. Unit 2 UFSAR, Amendment 12

4. Unit 2 Technical Specifications, Amendment 108

5. USNRC GENERIC LETTER 89-13 & Supplement 1

6. PCAJOB NO 0236-W- U1-1986

7. PCA JOB NO 3580 - Ul- 1988

8. PCA JOB NO 5670 - Ul- 1990

9. PCAJOBNO8177- Ul-1991

10. PCA JOB NO 9303 - Ul- 1992

11. PCAJOBN0O10813- U1-1993

12. PCAJOBNO13243- U1-1994

13. PCA JOB NO 15422- U1-1996

14. PCA JOB NO 16916- U1- 1997

15. PCA JOB NO 19089- U1- 1999

16. PCA JOB NO 0884 - U2- 1986

17. PCA JOB NO 1755- U2- 1987

18. PCA JOB NO 4330 - U2- 1989

19. PCAJOBNO6717- U2-1991

20. PCA JOB NO 9303 - U2- 1992

21. PCA JOB NO 12125 -U2- 1994

22. PCA JOB NO 14442 -U2- 1995

23. PCA JOB NO 16496 -U2- 1997

24. PCA JOB NO 17501 -U2- 1998

25. PCA JOB NO 19831 - U2- 2000

26. Work Order 29013348 - U2- 2000

St. Lucie Units I and 2 L-2013-005 Docket Nos. 50-335 and 50-389 Attachment Page 9

27. Letter ESI-NDE-93-149 - U1- 1993

28. Letter JPN-CSI-94-395 - U2- 1994

29. Specification SPEC-M-023, R3

30. Metals Handbook, Volume 13, Ninth edition

31. SSPC - Steel Structures Painting Council, Volume 1, 2ed edition 1989

32. Notes CR data base, reviewed 09/20100

33. NMRS data base, reviewed 09/20100

34. PSL-2FSM-00-004, Rev 1

35. PSL-1 FJM-93-016, Rev 1

36. CR 97-0127

37. EPRI TR-109937, Final report April 1998

38. Regulatory guide 1.54

39. FPL Letter L-90-28, dated January 25, 1990

40. Video inspection of the 2A2 well, year 2000

41. EPRI REPORT 1019157, December 2009, Guideline on Nuclear Safety-Related Coatings, Revision 2 (formerly TR-109937 and 1003102)

42. Action Request # 1740921, Unit 1 Intake Cooling Water Discharge Pipe Failure Root Cause Evaluation, April 5, 2012