RBG-26592, Forwards Response to NRC Bulletin 87-001, Thinning of Pipe Walls in Nuclear Power Plants

Forwards Response to NRC Bulletin 87-001, Thinning of Pipe Walls in Nuclear Power Plants

ML20234C594
Person / Time
Site:	River Bend
Issue date:	09/11/1987
From:	Booker J GULF STATES UTILITIES CO.
To:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
References
IEB-87-001, IEB-87-1, RBG-26592, NUDOCS 8709210347
Download: ML20234C594 (18)

Text

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1 a 4 GULF STATES ' UTILITIES ' COMPANY

. RAVER BEND STATION PO$1 OFFICE BOX 220 ' ST FRANC!SVILf. LOUISlANA 70776 AREA CODE 604 635 60944 346 8651 l

September.11, 1987 RBG-26592 File Nos. G9.5, G9.33.1-U.S. Nuclear Regulatory Commission [)

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> 611 Ryan Plaza. Drive, Suite 1000 Arlington, TX 76011

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Gentlement "

River Bend Station - Unit l' Docket No. 50-458 Attached .is Gulf . States Utilities Company (GSU) response to NRC Bulletin No. 87-01, Thinning'of' Pipe Walls in Nuclear Power Plants.

This. response provides the requested information concerning Gulf States Utilities program for monitoring the thickness of pipe walls in piping systems at River Bend Station.

If further assistance is required, please contact Mr. Rick J. King at (504)'381-4146.

Sincerely, Y'%

J. E. Booker Manager, River Bend Oversight River Bend Nuclear Group E / SF ch Attachment.

cc: U.S. Nuclear Regulatory. Commission Doc'ument Control Desk Washington, D.C. 20555 Senior Residen* Inspector Post Office Box 1051 St. Francisville, LA 70775 5\

8709210347Og9y58 -

'T-PDR ADOCK O PDR t g p sn - - - - - - -. -- - - - _ - ___

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UNITED STATES OF AMERICA-NUCLEAR REGULATORY COMMISSION i STATE OF LOUISIANA 5' PARISH OF WEST FELICIANA. $

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.In the Matter of. $ Docket No. 50-458 1 g GULF STATES UTILITIES COMPANY $

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.(River Bend Station. $

Unit 1)~ $

AFFIDAVIT

.' J . E. Booker, being duly sworn, states that-he is Manager-River Bend Oversight for-Gulf States Utilities Company; that he is authorized on the

.part of said Company to sign and file with the Nuclear Regulatory Commission the documents attached hereto; that he has read all of the statements contained in such documents attached thereto and made a part l thereof; and that all such statements made and matters set forth therein i

are true'and correct to the best of his knowledge, information and belief.

he f lh p.E. Booker Subscribed and sworn to before me, a Notary Public in and for the State and Parish above named, this' // day of deO beni Ae r ,

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j'oanW.Middlebtfooks v Notary Public in and for West Feliciana Parish, Louisiana  !

My Commission is For Life:

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• j RESPONSE TO ACTIONS REQUESTED IN NRCB NO.,87-01 This response will address each of the' actions requested in NRC Bulletin No. 87-01: Thinning of Pipe Walls in Nuclear Power Plants. Attachment 1' lists specific line numbers identified by Engineering as being susceptible to. Erosion / Corrosion. Attachment 2 is the' General Electric Design' Specification, 22A5495 Revision 1, Lused by. Stone and Webster Engineering Corporation in determining the corrosion allowances used in wall thickness evaluation.

1. Safety- related (QA Cat' I) carbon steel piping. was' designed, fabricated, and erected in accordance with ASME III .1974. Codes & '

Standards: Design, fabrication, and erection of non-safety related (QA Cat. II) carbon steel piping was in accordance with ANSI

'B31.1-1973 through Winter,- 1979 Addendum, Table 126.1, Specifications ~ (Piping- material - ASTM A106, CR.B; fittings - ASTM A105 & A234WPB).

2. Scope- and Extent: The' Erosion / Corrosion Control Program is described in Engineering Department Procedure-Mechanical Engineering-71 (EDP-ME-71). This procedure describes the purpose as establishing and implementing through the Maintenance Work Order a program of augmented inspection and analysis of Balance of Plant (QA Cat II) high energy, carbon steel. piping for the purpose of detecting evidence of pipe wall thinning caused by erosion / corrosion (E/C).

EDP-ME-71 briefly explains the various erosion / corrosion parameters and establishes acceptance criteria for the inspection results.

These inspections will be performed by qualified Quality. Control (QC) personnel using their approved visual and ultrasonic (UT) procedures. The procedure also gives guidelines on selection of sections of piping or components having greater potential for wall thinning due to erosion / corrosion. Keller's Equation is to be used as the. primary basis for prioritizing components for inspection during- future outages. The first refueling outage will have an

,. ' abbreviated inspection effort for the purpose of gaining experience.

Inspections will include areas of piping identified by~ industry failures as being'nighly susceptible to erosion / corrosion: 1.e.,

condensate suction to feedwater pumps, feedwater short cycle min-flow recire, heater drains, extraction, and turbine cross-under piping. Nine lines have been identified and two control valves will be disassembled and inspection.

Erosion / corrosion inspection is applicable to all high energy (high temperature and high pressure) carbon steel piping and components in the balance of plant (QA Cat II). The inspections are QA-Not Applicable.

The following systems are included in the Erosion / Corrosion Control Program (additions / deletions may be made based upon industry and station inspection experience):

Cold Reheat (Turbine Cross-under Piping)

Hot Reheat (Turbine Cross-over Piping)

High Pressure Turbine Extraction Low Pressure Turbine Extraction Heater Drains and Vents Feedwater Condensate Specific line numbers identified by Engineering as being susceptible to Erosion / Corrosion are shown on Attachment #1.

Inspections will be documented (by mapping where necessary) and attached to the Maintenance Work Order (MWO) package._ Engineering will review the inspection results to criteria identified in EDP-ME-71 and make recommendations to maintenance accordingly.

Reinspection schedules will be calculated and recorded in accordance with EDP-ME-71.

a. The inspection points selected for thickness measurements are described in EDP-ME-71. Basically, they consist of elbows, and downstream of valves, orifices, and other flow restrictions.

b. The frequency of inspection is based upon 100% inspection of the susceptible pipe Ifnes identified by Engineering (Attachment #1) by the sixth refueling outage. This equates to approximately ten (10) years, which is the industry average for experiencing these types of failures. Frequencies of inspected piping will be adjusted according to the results as described in EDP-ME-71.

With regard to the inspection of high steam flow piping for evidence of internal pipe wall erosion, Engineering requires inspection of the following during each refueling outage:

Extraction From HP Turbine (Rotate the inspection of the lines and MSR inspected during each subsequent outage, such that all similar items and lines will be inspected by the sixth outage.)

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1. One of the six (6) cross under pipes form the High Pressure (HP) l Turbine to the Moisture Separator Reheater (MSR) and inlets of one of the MSRs.

2. All elbows of one of the two extraction lines from the HP Turbine to the first point feedwater heaters (line nos.

1ESS-107-4; IESS-108-4).

3. All elbows including the initial branch tee of one of the two extraction branch lines off to the cross under piping to the 2nd ,

point feedwater heaters (line nos. IESS-105-4; IESS-106-4). l l

Feedwater Drains and Auxiliary Systems I (Inspect in accordance with QC inspection procedures for UT including the first elbow down stream of the flow control valve.

Rotate the inspec. tion .of the selected lines during subsequent outages. such that all similar lines will be inspected by the th1rd refueling outage), j

4. One of the three feed pump min-flow recirculation lines.

5. The feed pump start-up.line to the condenser.

6. One of the two ist. point heater drain lines to the condenser.

7. One of the two ist point heater drain lines to the 2nd point heaters.

8. One of the two 2nd point heater drain lines to the condenser.

9. One of the two 2nd point heater drain lines to the 3rd point d heater.

10. One of the two 3rd point heater drain lines to the condenser.

11. One of the two 4th point heater drain lines to the condenser.

12. One of.the two 4th point heater drain cooler lines to the  !

condenser.

13. One of the two 5th point heater drain cooler lines to the condenser.

14. One of the two drain receiver tank drain lines to the condenser.

Quality Control will verify and document these inspections and a copy of the inspection results will be sent to Engineering for evaluation. Depending upon the inspection results, the intervals for inspection may be adjusted by Engineering accordingly.

Should any significant evidence of pipe wall erosion be detected, then the remaining lines which perform similar functions must also be inspected for possible deterioration. Additional direction will i be provided by Engineering.

For each of the lines listed, excluding those in the Extraction Steam System, the area of concern is that portion of each line including and immediately downstream of the control valve. In each case, the pressure drop imposed by the valve could cause " flashing" and " cavitation" should occur at a poitc. less than f1ve (5) pipe diameters downstream of the control vab es.

The potential impact on operations due to erosion has been reduced in the design phase by either increasing the wall thickness of the

downstream piping or utilizing materials (e.g., 1-1/4 CR- 1/2 Mo or

304 SS) in the downstream piping that are more resistant than carbon l steel to the effects of erosion.

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. i i For the Extraction Steam System, the concern is the creation and

" carryover" of moisture in the steam at relatively high velocities that might cause erosion. This effect could occur anywhere in the ,-

system during operation. Again the potential impact on operations due to erosion has been reduced during the course of design by the extensive use of 1-1/4 CR- 1/2 Mo and 304 SS piping in this system.

A. Periodic Inspection of Control Valve Internals The internals of each control valve noted in Attachment I should be inspected periodically for erosion damage. In those cases where an increase in noise, an increase in vibration or a decrease in the efficiency of the control valve is noted during operation, immediate inspection is warranted.

B. Periodic Ultrasonic (UT) Inspection of Downstream Piping The wall thickness of each line noted in Attachment I downstream of the appropriate control valve should be inspected periodically for erosion damage via UT inspection. As a minimum, all piping should be scanned linearly from the control valve to a point five (5) pipe diameters downstream of the control valve (including fittings and bends) starting at each of four (4) positions around the piping (i.e., the 3:00, 6:00, 9:00 and 12:00 o' clock positions). An unacceptable indication of erosion is considered as any reading where the wall thickness is less than the minimum wall thickness (including manufacturing tolerances) for the specified schedule or nominal wall thickness of the piping installed. Should any indications of erosion exist in the first five (5) pipe diameters, the scan should be continued at one (1) pipe diameter intervals until no indications exist for at least two (2) pipe diameters.

C. Periodic Ultrasonic Inspection of Extraction Steam Piping The wall thickness of the Extraction Steam System lines should be inspected periodically for erosion damage via UT inspection.

All carbon steel Extraction Steam System lines except those i lines in the condenser should be scanned starting at each of the i first two changes in direction downstream of the extraction i point, for a distance not less than five (5) pipe diameters. If i erosion exists at the second change in direction, the scanning f should be continued to the next change in direction, etc.

D. Evaluation and Resolution of Erosion Indications All indications of erosion in valves and piping shall be brought to the attention of Engineering for evaluation and resolution as j deemed necessary by Engineering.

The below listed minimum inspections are to be performed during the Reload-1 refueling outage. This will allow River Bend to begin an Erosion-Corrosion Monitoring Program, and gain experience. Future inspections will be adjusted based upon experience. Since this first inspection is an attempt to initiate an erosion / corrosion 1 l

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, i inspection program, the criteria to which these first inspections are made are based mainly upon flow velocities, operating and design temperatures, and operating and design pressures. The Line Designation Table (LDT) was consulted and the selections were made to include those carbon steel lines which operate within a band of 350+90*F, and pressures having significant damage or injury potential (i.e. operating / design pressure greater than 100 psig).

1. Visual interior inspection of 42" steam cross-around piping form the HP Turbine to the MSR-1 inlet. (Approximately 60 ft.)

2. Extraction steam line (1ESS-010-107-4) from HP Turbine to the first Pt. Heater A will receive four UT scans of four feet in length at the nozzle, and circumferential band of UT at each downstream weld.

3. Extraction line off 42" cross-around to the second pt. heater (1ESS-016-106-4) will receive four UT scans of up to seven feet in length at the nozzle, and circumferential band of UT at each downstream weld.

4. Heater drain line (1 HDL-020-100-4) from discharge of heater drain pump, PIB and downstream from flow control valve (LV-4A) to condensate line (ICNM-020-78-4) will receive four UT scans of eight feet in length past the control valve and past a 90* elbow and gate valve (V258) with a circumferential band of UT at each downstream weld.

5. Heater drain line (1HDL-012-4-4) from the second Pt. Heater A to the third Pt. Heater A vill receive four UT scans of five feet at each of five 90* elbows, plus an inner and outer grid inspection (UT) at each elbow, and circumferential band of UT at each downstream weld of the above fittings.

6. Feedwater Pump C suction line (ICNM-020-82-4) will receive four UT scans for three feet past the 20x14 reducer including one 45* elbow, plus a circumferential band of UT at each downstream weld of the above fittings.

7. Feedwater short cycle min-flow recire line (IFWR-010-6-4) to connection 5A of the condenser will receive four UT scans for four feet past the flow control valve, plus a circumferential band of UT at the downstream weld of the valve.

8. HP Heater drain line (1HDH-016-13-4) from the first Pt.

Heater B to connection 9B of the condenser will receive four UT scans for seven feet in length past each of five 90*

elbows, plus a circumferential band of UT at the downstream weld of the elbows.

9. HP Heater drain line (1HDH-010-4-4) from the first Pt. Heater l A to the second Pt. Heater A will receive four UT scans four feet in length at each of two elbows, plus an inner and outer grid inspection (UT) at each 90* elbow and circumferential band of UT at each downstream weld of the above fittings.

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'10.::Two flow control valves (IFWR-FV2A, lHDH-LV26A) will be disassembled and visually inspected for erosion / corrosion.

c. The methods'used-to measure' thickness are visual'and ultrasonic h (UT) as described in EDP-ME-71.- These UT inspections will be in accordance with approved QA procedure QCI-3.28. '

d. Repair / replacement decisions are described in. EDP-ME-71 and

. basically are determined by the design minimum wall thickness.

L Any inspections which measure at or below the design minimum L z wall thickness will be recommended for repair / replacement depending on the actual individual-circumstances.

3. Criteria .used for_ selecting points of inspection -for both liquid-phase 'and ftwo-phase systems are described in EDP-ME-71 and include the following~ factors:

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a. Piping material - carbon steel (lines fabricated of stainless or l

Cr-Mo steel are not selected).

I- Note:' Most of the turbine extraction piping is either 304 stainless or 1-1/4 Cr-1/2 Mo.

b. Piping configuration - all fittings and restrictions to flow will be inspected. Piping configuration can also have a significant impact on turbulence. At .Surry, the feedpump suction line has- two quick changes in flow direction whereas with the River Bend design the suction line branches off the main header at a 45 degree angle and eventually levels out using a 45 degree elbow. This is a more favorable transition.

The piping selected at the Surry unit was 18" extra strong, which has a nominal wall thickness of 0.5 inches (min. code allowable is 0.36 inches). The piping at River Bend'is 20" sch.

40, which has a nominal wall thickness of 0.59 inches (min, code allowable is 0.39 inches). This provides River Bend with an additional 60 mils of pipe wall.

A review of the steam piping systems materials and design indicate that the extraction steam system piping was designed to utilize long radius elbows and adequate drains to remove moisture. The extraction steam-inside the condenser, feedwater heater und MSR drains downstream of the level control valves subject to flashing utilize type 304 stainless steel. The extraction steam-outside condenser utilizes 1-1/4% chromium, 1/2% molybdenum materials. Gulf St&tes Utilities does not believe the extraction steam piping containing 1-1/4% chromium and 1/2% molybdenum or stainless steel type 304 requires upgrade since the pipe materials containing one to two percent chrome are four to five times more resistant to erosion than carbon steel and stainless steel is roughly one thousand times more resistant.

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1. According to INP0 SOER No. 82-11, piping materials which contain I to 2 percent chrome have been found to reduce erosion rates by a factor of four to five times over carbon steel. A review of the extraction steam system flow diagrams shows the use of 1-1/4 percent chrome and 1/2 percent molybdenum steel piping material. This choice of material was applied to the piping for the first to fourth point heaters employ the use of a stainless steel piping material. The referenced INPO report states that his material can be significantly more resistant to erosion than carbon steel. The use of these materials alone would help to minimize the risk of piping system erosion.

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2. Although it is virtually impossible to remove all configurations which might promote erosion of the piping system, efforts are being taken to ensure that the potential l

1s reduced where possible. A review of the piping '

arrangement drawings associated with extraction steam was conducted. In general, all piping is sloped to prevent water traps, and no reducers were used that would create a water trap. Where lines are tied together in a manner where steam jet impingement could occur, lateral fittings have been used.

l c. PH is maintained between 5.6 and 8.6 in accordance with the GE I BWR-6 Fuel Warranty and Tech Spec Table 3.4.4-1; therefore, it l need not be considered in determining erosion / corrosion deterioration.

d. Temperature - system design temperatures greater than 260*F are included,

e. Velocity - high energy or systems having the potential for high flow or if unconfined may cause severe damage or personal injury, i.e., having pressures greater than 100 are included.

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Based on the data supplied by INPO and the NRC, the fluid velocity at the Surry unit was 17.6 feet /second. At River Bend the fluid velocity thru the feedwater suction line is 10.5 feet /second. This shows a 33% decrease in feed water flow which would indicate less turbulence. Damage at the Surry unit occurred after the unit was operating for over 13 years as compared to River Bend's one year of operation.

f. Oxygen content is mainrained between 20-50 ppb in accordance with the GE Fuel Warranty and does not need to be considered in determining erosion / corrosion determination.

NOTE: Although the water quality is set by Fuel Warranty and cannot be adjusted, it can be seen that the oxygen content, is high enough to inhibit erosion / corrosion.

4. Refueling Outage (RO) - #1 will be the first opportunity to initiate inspections specifically conducted for the purpose of identifying pipe wall thinning caused by erosion / corrosion.

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y c. L a, b, &;c The.~only inspection' conducted. to' date which. was specifically Jconducted for investigation of erosion / corrosion was performed via Maintenance Work Order-(MWO) 108559 this spring. . This inspection was a UT scan of

the first elbow downstream'of a' relief valve in a high radiation area on the. heater drain system which was isuspected of. leakage past'the' seat 'and flashing to the-condenser.- The piping nominal thickness was .375 in. with a minimum design wall thickness of .276 in. Results of the -inspection were thicknesses of between .420 in. and

.450'in. for,the radius of the elbow and between .380 in, and. 390'in, at both ends of.the elbow. All results were acceptable being greater .than' the specified nominal thickness.

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d. The only other: piping . area identified as having significant I erosion / corrosion problems .was. the feedwater short-cycle min-flow _ recirc line back to the condenser.- This piping was so badly eroded'during the start-up phase of :the plant that .the-segments' .between the control valves and . isolation valves downstre'am-of the control valves-for'each of the three pumps was replaced with' stainless steel..

5L. River Bend. has no plans for developing new or additional programs-

for monitoring pipe wall' thickness. The present program is-recently developed and is expected to be revised and refined as experience is gained during these inspections.

The safety-related . systems are not presently included in the' Erosion / Corrosion ' Control Program. Culf States Utilities believes

-that the ASME XI Inservice Inspection program examinations of welds will' identify evidence of any. erosion which will lead to further ultrasonic wall thickness' examinations if warranted.

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• Revisim 0 Page 22 of 45 ATDOM!NP 7.15.1 Page 1'of 3 l

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BOP piping lines which should be considered for inspection as being susceptible to erosion / corrosion.. (Addition / deletions to this list may be made based upon industry experier.ce); '

Line Number FSK PID _EP

1. 42"-Steam Cross-Under (6) Visual 3-2 4-2G

2. 42" Steam Cross-Over (4) Visual 3-2 4-2G

3. 1ESS-010-107-4 3-4A 4-2G 4, 5

4. ,1ESS-010-108-4 3-4A 4-2G 4, 5

5. 1ESS-016-106-4 3-4A 4-2G 4, 5

-6. .1ESS-016-105-4 3-4A 4-2G 4, 5

7. 1HDL-018-98 4-2A 4-2C 25

8. 1HDL-006-13-4 4-2A 4-2C. 25 l

9. lHDL-016-125-4 4-2A 4-2C 25

10. 1HDL-016-126-4 4-2A 4-2C 25

11. 1HDL-020-11-4 4-2A 4-2C 25 12.' 1HDL-020-102-4 4-2A 4-2C 25

13. 1HDL-003-136-4 4-2A 4-2C 25

14. 1HDL-003-135-4 ~4-2A 4-2C 25 15.'1HDL-018-37-4. 4-28 4-2D 25

16. 1HDL-018-91-4 4-2B 4-2D 25

17. 1HDL-020-89-4 4-2B 4-2D 25

18. 1HDL-014-115-4 4-2B 4-2D 25

19. 1HDL-006-38-4 4-2B 4-2D 25 20, 1HDL-020-36-4 4-2B 4-2D 25 21 1HDL-016-123-4 4-2B 4-2D 25 22, 1HDL-016-124-4 4-2B 4-2D 25

23. 1HDL-020-93-4 4-2B 4-2D 25

24. 1HDL-008-43-4 4-2C 4-2E 25E 25, 1HDL-008-21-4 4-2C 4-2E 25E

26. lHDL-010-55-4 4-2D 4-2F 25E

27. 1HDL-016-54-4 4-2D 4-2F 25E 28, 1HDL-006-65-4 4-2D 4-2F 25E

29. 1HDL-016-63-4 4-2D 4-2F 25E

30. 1HDL-008-64-4 4-2D 4-2F 25E

31. 1HDL-010-70-4 4-2E 4-2F 25E

32. 1HDL-016-69-4 4-2E 4-2F 25E

33. 1HDL-006-80-4 4-2E 4-2F 25E

34. 1HDL-016-78-4 4-2E 4-2F 25E

EERR 87-RO3C9 l2

'. ArrAcHMENT *l p is cf ;#j Mmewr EDP 4E-71 Revisicm 0 Page 23 of 45 ATDCRE!Nr 7.15.1 Page 2 of 3 Line Number FSK PID _EP 35, 1HDL-012-4-4 4-2A 4-2C 25

36. 1HDL-018-12-4 4-2A 4-2C 25

37. 1HDL-018-6-4 4-2A 4-2C. 25

38. 1HDL-020-16-4 4-2A 4-2C 25

39. 1HDL-020-148-4 4-2A 4-2C 25

40. lHDL-012-29-4 4-2B 4-2D 25

41. 1HDL-018-31-4 4-2B 4-2D 25 42, 1HDL-020-41-4 4-2B 4-2D 25

43. 1HDL-020-150-4 4-2B 4-2D 25

44. 1HDL-008-151-4 4-2C 4-2E 25E

45. 1HDL-008-67-4 4-2C 4-2E 25E

46. 1HDL-010-24.-4 4-2C 4-2E 25E

47. 1HDL-010-152-4 4-2C 4-'2E 25E

48. 1HDL-008-44-4 4-2C 4-2E 25E

49. 1HDL-008-153-4 4-2C 4-2E 25E 50, 1HDL-010-46-4 4-2C 4-2E 25E

51. 1HDL-010-154-4 4-2C 4-2E 25E

52. 1HDL-008-56-4 4-2D 4-2F 25E

53. 1HDL-010-155-4 4-2D 4-2F 25E

54. 1HDL-012-58-4 4-2D 4-2F 25E 55, 1HDL-014-156-4 4-2D 4-2F 25E

56. 1HDL-008-71-4 4-2E 4-2F 25E 57, 1HDL-010-157-4 4-2E 4-2F 25E 58, 1HDL-012-73-4 4-2E 4-2F 25E

59. 1HDL-014-158-4 4-2E 4-2F 25E

60. 1HDL-008-79-4 4-2E 4-2F 25E

61. 1HDH-016-6-4 6-6 4-2A 61

62. 1HDH-010-4-4 6-6 4-2C 61

63. 1HDH-016-13-4 6-6 4-2B 61

64. 1HDH-010-11-4 6-6 4-2D 61

65. 1EWS-020-1-4 6-1A 6-1A 17A

66. 186-020-2-4 6-1A 6-1A 17A

67. 1Ews-020-3-4 6-1A 6-1A 17A i

68. 1FHS-008-1-4 6-1A 6-1A 17A

69. 1EWS-008-3-4 6-1A 6-1A 17A {

70. 1Eus-008-5-4 6-1A 6-1A 17A  !

71. 1FWS-012-12-4 6-1A 6-1A 17A I

72. 1FWS-012-13-4 6-1A 6-1A 17A

73. 1Ews-020-10-4 -

6-1A 6-1A 17A q 74, 1Ews-020-5-4 6-1A 6-1A 17A l

75. 1FWS-020-9-4 6-1A 6-1A 17A

76. 1Ews-020-6-4 6-1A 6-1A 17A 1

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Page 3 of 3 Line Number FSK PID g

77. 1FWS-020-8-4 6-1A 6-1A 17A

78. 1EWS-020-7-4 6-1A 6-1A 17A

79. 1EWS-020-80-4 6-1B 6-1A 17B

80. 1EHS-020-30-4 6-1B 6-1A 17B j

81. IEWR-010-6-4 6-3 6-1A 57A

82. 1HDL-014-110-4 4-2A 4-2C 25

83. 1CNM-020-82-4 4-1E 4-1B 18A' (18K)

84. 1CNM-020-83-4 4-1E 4-1B 18A (18K)

85. 1CNM-020-84-4 4-1E 4-1B 18A (18K)

86. 1EWR-008-1-4 6-3 6-1A 57A 87, 1EWR-008-3-4 6-3 6-1A 57A 88, 1EWR-008-5-4 6-3 6-1A 57A

89. lEWR-010-2-4 6-3 6-1A 57A -!

90. 1EWR-010-4-4 6-3 6-1A 57A I i

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/ YERIPIC&TI0I 0F BIFIN.EZIIBUB IALE AND C08803 ION ALLCR4ppy IN I' - -jach system tagineer is required sinissa vall thickness of the piping in his system to verify and the_ 1.25 L

to verify the adequacy of the corrosion allevance. Sritical 1.'28 also 1.2/

l systems (i.e., asia steam, feed vater, condensate, residual heat removal, and reactor t' greater than 24 la diameter mater- cleanup) and all piping 1.29 i are to be verified -)y: an 1.30 1

individual calculation checked. by a Piping Engineer. ,

Jacentioans (a) extraction steam piping

.' Xndd 8 PTP 26.1.7-0 and pipe covered by 1.31 i service, (b) interna $he classes specified for that .1.32

( aonsetallic pipiag.

lly lined pipe er plastic pipe, and '(c) 1.33 )

includia'g critical piping, will be 1.34 All piping, verified siniana vall issue of Jine by means of the Designation Tables (LDT). 2he_ 1.36 the LDT cospetes and prints out the 1 l

sinians glaculated design tem wall thickness for piping based upon the 1.37 3ressure, pipe class) perature, inputted for and each' pipe material (based on 1.38 line froe Ahediagram.

flow 1.39

, 2he systen En gineer is to follova:

perfore this verification- as 1.40 i L

R3113itinas i 1.42 i Jigiana Calgulated Wall Thigjgg33-(Tae) 1.44

)

(

j 2he piping wall thickness calculated from the design

1.45-

- formula ANSI B31.1give in 1551 III '(Article 58, NC, et 50 3641) or. 1.46 (paragraph 104) ssing design pressure, 1.47 i by individ ual calenlation or as given ,(pipe class),

temperature, and material stress allowable 1.48 I designation tables. in the line i

l i

Minimus Manufgg3sggj Wall ( T a)_ 1.49 I

I 2he piping wall thickness minians as supplied s tan dard supplied Ripe (see S8W STD-SP-1056-1-5 on 1.50 or established by salenlation or 1.51 STD- S P-10 56 5) for 1.52 )

Xndd 8 special pipe (larger than 24 inch OD), see PTP 26.1.1-0.

Corrosion allowamce iat 1.53 Jacess material above minians calenlated wall to allov 1.54 for the corrosion power ga the ID of the piping during the life of 1.55 plant, or as defined

>l

': &NSI 331.1, and additional thickness to la 455E III and (1) compensate 1.56 for 3aterial removed la threading, (2) provide for 1,57 corrosion and/or erosion, and J3) provide for structural 1.58 strength of the pipe during erection.

Zoe the River Bend Project the' corrosion allowance for

.f either rolled and gelded SA-156 pipe or for piping 2.2 2.1 l chr-12210-1200j 10/15/83 124

LM!

Arracumcur *2 EEAR 87dC3C9p&4gf1

/... o, Py e n cf gg 4M i systems which will contain acidic,5austic or other 2. 3 highly corrosive fluids shall be obtaine;d from, the Lead jgatorials Engineer. ssW 311 other piping on the River 2. 5 '

X Add 6 Bend og project will use the corrosion allowance standards 2.6 gg-NEBG Specification No. 22A-5495, Appendix III (attached) . Revision 1, or J,inimum corrosion 311owance shall be .080 in. for m 2. 7carbon

2. 0 steel and .002 in. for stainless steel.

1. On LTDs verify line class) , design numbers . (size and code pressure, 2.10 material (pip class) . j;emperature, and 2.11 J. compare Tac from calculation or LDT to "Tm" 2.12 (STD-SP-1056) thatn "Taca. to ensure _that atma is not less 2.13 J. If Item 1 above is satisfactory, subtract "Taca from "Tma and determine 2.14 the available 2.15 corrosion allowance aaa: ~

a=Tu - Tme.

2.17 4 compara and verify that ama is in compliance 2.19 with the criteria stated above.

5. If Items 1, 2, and 3 above are not satisfied, 2.20 a higher pipe class must be specified. >

I

{ chr-12210-1200 j 11/17/82 124 k

EEAR 1740.5c p?

+

. ATracumeNr 2

. . .X .Add ' . 6: -

l.- D-4 y

<J3 ch' ,

SENERAL$ILICTRIC

, As4ts = =. 12s -

auctuam emenoyavmon aty. I

,- Arrenots tus -

CDRRO$10N ALLOWAMCt

1. CORA0310N ALLOWANCI , ,

1.1 The following 40-year service life cor.resion allowances. based on corrosion I

. of one surface. have been includd in the Appendix !!.Scheevles which are used la the WR piping for which E has system responsibility. In those systass that are the responsiht11ty of others tt represents the mcommendatians of General Electric.

1.1.1 Carbon Steel tvstan=

Service terrosion Allowance inches

' (1) Contral Aod Drive Hydraulic Main Flow Lines satarmittant Flow Lines

• 0.080 0.080 (2). Reactor Water Clean-up Systasi *

'0.030 (3) Precoat Systans

, 0.000 "

(4) Re' actor Core Isola'tfon Cooltag 0.040 (5) Nigh Pressure Caelant Injection er Nigh Pressure Core Spray System -

' ' ~

0.080 (4') Core Spray Puap Suction and Discharge Piping '

' Piping Exposed to Reactor Watar , 0.080

.(7) Main Staas. M5!Y. Laakage contret Systan' . -

O.120 (8) Normally Flowing Auxiliary 3 teas Lfnas

, 0.120 .

(9) Normally Non-Flowing Auxilf ary Staan Lines 0.120 (10) Staas Line Oratas 0.120 (11) 4WR Watar (0.01 ppe Og ) 212*F 0.2

, 100*F 02 Saturated Watar ,0.040 (It) Feedwater -

~ 0.000 d (13) Fuel Pool Cooling System ..

, ,' 0.000

/ s, . ,

~

. EEAR 87-RCsc  :

o. -

x 4s4 4, N.rrAcHmsnr*2 P*p y c9 l .

D-5 .

ww<ifij, SIN ER AL @ ILICTRIC 22As4ss . m, Its -

mm.uasaamovomsen ,,,, I rinAL APPDI0lt !!! ,

1.1.1 (Continued)

Service . Corrosion Allowance fnees 1

Residual Heat Removal Systas - -

(14) RM Piping taposed to Reactor Water .

0.080 (15) Reactar Ver.t -

0.040 (14) Reactor vessel Flange Leak Offs 0.040 (17) Raaster Vassel Orata (next to vessel)

• 0.000 ,

(la) Off-sas System Process Lines 0.120 (19) Deserstad Candensate ,

0.010 (20) Condensata and Destneralized Watar from Storage 0.000

, (21) Closed Coolind Water System ' O.100 (22) RaMsta Disposal - Lfquid .

0.080 (23) Non Flew Watar Piping (full during operation) 0.020

-(24) Suppress,1on Pool 0.250*

1.1.2 Stafnless steel $wtems ,

All Services 0.003

. \

1.1.3 A1ustnum Allor intees All Services ~

0.010 l 1

. . l 1

l

~

~

Tor submerged ofpine tAere two surfaces are wat the corroston allowance should be 80weled to 0.$00. itifaless steel is recommended for use in ts ead of carbon steel d for piping in the suppression pool. In weten case cerrosion alloence should be 0.006. .

4 .