ONS-2015-108, Response to Request for Additional Information (RAI) Regarding Relief Request 15-ON-001, Repair of Low Pressure Service Water System Piping

Response to Request for Additional Information (RAI) Regarding Relief Request 15-ON-001, Repair of Low Pressure Service Water System Piping

ML15295A309
Person / Time
Site:	Oconee
Issue date:	10/16/2015
From:	Batson S Duke Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
ONS-2015-108, TAC MF6374, TAC MF6375
Download: ML15295A309 (10)

Text

Scott L. Batson DUKEVice ENERGYOconee President Nuclear Station ONO1VP I 7800 Rochester Hwy Seneca, SC 29672 ONS-201 5-108 o: 864.873.3274 f.. 864.873. 4208 Scott.Batson@duke-energy.com October 16, 2015 ATTN: Document Control Desk 10 CFR 50.55a U.S. Nuclear Regulatory Commission Washington, DC 20555 Duke Energy Carolinas, LLC (Duke Energy)

Oconee Nuclear Station (ONS), Units 1 and 2.

Docket Numbers 50-269 and 50-270 Renewed License Numbers DPR-38 and DPR-47

Subject:

Response to Request for Additional Information (RAI) regarding Relief Request 15-ON-001 Repair of Low Pressure Service Water System Piping (TAC NOS. MF6374AND MF6375) (ADAMS Accession No. ML15252A474)

Pursuant to 10 CFR 50.55a(z)(2), Duke Energy submitted Relief Request 15-ON-001 on June 12, 2015, requesting that NRC grant relief from the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) regarding a specific repair/replacement activity at Oconee. The NRC submitted a Request for Additional Information on September 16, 2015 regarding this Relief Request. The Duke Energy response to the RAI questions is attached as an enclosure to this letter.

There are no regulatory commitments associated with this letter.

If there are any questions, or further information is needed, you may contact David Haile at (864) 873-4742, Sincerely, Scott L. Batson Vice President Oconee Nuclear Station

Enclosure:

Oconee Nuclear Station Unit 1 and 2, Response to Request for Additional Information (RAI),

regarding Relief Request 1 5-ON-001 Repair of Low Pressure Service Water System Piping.

ONS-2015-1 08 October 16, 2015 Page 2 CC :

Mr. L. D. Wert Jr.

Administrator Region II (Acting)

U.S. Nuclear Regulatory Commission Marquis One Tower 245 Peachtree Center Ave., NE, Suite 1200 Atlanta, Georgia 30303-1257 Mr. James R. Hall, Project Manager (ONS)

(by electronic mail only)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Mail Stop O-8B1 Rockville, MD 20852 Mr. Jeffery Whited, Project Manager (by electronic mail only)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Mail Stop O-8B1A Rockville, MD 20852 Mr. Eddy Crowe NRC Senior Resident Inspector Oconee Nuclear Station

ONS-2015-1 08 October 16, 2015 Page 3 boo:

T.D. Ray (ON01 VP)

J.E. Burchfield (ON01 VP)

T.L. Patterson (ON01 VP)

C.J. Wasik (ON03RC)

H. Galloway G.L Armentrout A.D. Best P.W. Downing, Jr.

M.A. Pyne M.J. Ferlisi S.H. Clark G.D. Scarboro IS! File ONS Master File (ON02DM, File OS 801.01)

ONS Information Service and Compliance ELL (EC2ZF)

ONS-2015-108

Enclosure:

Response to Request For Additional Information Enclosure Oconee Nuclear Station Unit I and 2, Response to Request for Additional Information (RAI), regarding Relief Request 15-ON-001 Repair of Low Pressure Service Water System Piping Page 1 15-ON-OO1 RAI Response re:

RAI Response re: 15-ON-001 Page 1

ONS-2015-108

Enclosure:

Response to Request For Additional Information

RAI-1

Section 5.1, Item 1 of the relief request states, "Replacement pressure retaining parts shall comply with the Construction Code (ASME B31.1-2007) and Owner's requirements.... The modification has been designed such that the piping system no longer relies on the encapsulated parts for structural integrity or leak tightness."

(1) Discuss the design pressure and temperature of the outer pipe.

Duke reply: The design pressure and temperature for this portion of the LPSW system is 100 psig and IO0°F. The outer piping (the encapsulation) was designed based on this pressure and temperature.

(2) Clarify how the outer pipe is analyzed to satisfy the allowable stresses in ASME B31 .1. Discuss how the applied loads (i.e., forces and moments) on the outer pipe are calculated or obtained.

Duke reply: Two enveloping cases were applied as computer models for analyzing the outer pipe stresses:

a) One model assumed a normal pipe wall thickness for the 3" piping (full of water and pressurized) and modeled the 6" piping as empty but pressurized; b) The second model assumed a corroded wall thickness of 0.15" for the 3" piping (empty and pressurized) and modeled the 6" piping as furl of water [including the inner 3" portion] and pressurized. This model also considered that any stiffness contribution from the corroded 3" piping was insignificant (near zero).

In both cases, the 3" piping and 6" piping were modeled as separate members (elements) and not as a combined composite member. The pipe stresses were computed separately as well. The maximum stress ratio's (actual stresses / allowable stresses) for all Code equations is less than 0.125; therefore, stresses are well within 831.1 allowable values.

(3) Identify any supports located at or in the vicinity of the existing pipe and the outer pipe.

Duke reply: The original 3" pipe run had no external supports in the span between the 36" header and LPSW-30. The first support along the 3" pipe run is a hanger 11 inches downstream of the 3" tee where LPSW-27 and LPSW-30 merge to supply LPSW flow to the MDEFW Pump Motor Coolers (see Figure 1 below). The design analysis of the new piping configuration as described in the relief request found no need to add any intermediate supports.

RAI-2

Section 5.1, Item 2 of the relief request states, "Ultrasonic thickness measurements shall also be performed where the encapsulation is to be welded to the 36-inch pipe header...

to confirm that material thickness is adequate for the encapsulation design."

Discuss the allowable minimum pipe wall thickness of the 36-inch header to which the encapsulation will be welded.

Duke reply: Ultrasonic Testing (UT) was performed to determine the 36" pipe header wall thickness in order to evaluate, 1) circumferential (hoop) pressure stresses, and

2) longitudinal (bending) stresses.

a) The lowest thickness reading obtained was 0.258". The minimum required thickness for circumferential (hoop) pressure stress per the 831.1 Code is 0.141" (Code Train)-

Therefore the 36" pipe wall thickness was found is acceptable with respect to circumferential (hoop) pressure stresses.

RAI Response re: 15-ON-001 Page 2

ONS-2015-108

Enclosure:

Response to Request For Additional Information b) The minimum average circumferential wall thickness was found to be 0.343". The mill tolerance value for this 36" Standard Schedule pipe is 0.328" (i.e., 87.5% of nominal).

Therefore longitudinal (bending) stresses for this pipe header were found to be acceptable.

It should be noted that a circumferential reinforcement, 3/8" thick and 3" wide, was installed on the 36" pipe around the encapsulation where it connects to the 36" header.

RAI-3

Section 5.1, Item 3 of the relief request states, "The locations where the encapsulation is to be welded to the system pressure boundary are located sufficiently far from locations of identified wall thinning to preclude the growth of identified corrosion from challenging the integrity of the encapsulation for the remaining life of the component to which the encapsulation is welded.

Discuss the minimum acceptable distance between the location where the encapsulation will be welded and the location where wall thinning occurs, presumably, on the 36-inch piping.

Duke reply:

Figure 1 Simplified sketch of the pipe configuration related to this Relief Request.

Note: Adequate flow to EFDW motor 2.* , " -. coolers can be provided by either

............... [....,

PS W-27 or LPSW-30 flow paths B-LPW SpplPmp toLPS*-' 27 lit Hanger on 3" LPSW piping LPSW header (1 of 3 pumps)

V ill,  ;

~LIMSW J[LJ,'(L

,*EFBW Pl-J*

TI)

• ,* Approx. 4 feet of

i..new 3" pipe was

• - *' installed in 2014

', Appox 4 feet of degrading

! 3" pipe remains F "outer pipe.

• .... - - - Outer I*pe is supported by welds at J"I

• j 36" Header and welds on to flange

.,'.,.......-? "

........ connection at valve LPSW-30 3" inner pipe is unsupported by the Scope of outer pipe I'iii l5l l ll ll, U-Page 3 re: 15-ON-9O1 RAI Response RA! Response re: 15-ON-001 Page 3

ONS-2015-108

Enclosure:

Response to Request For Additional Information (Clarification:The encapsulation/outerpipe has already been installed as a design change in accordancewith the Oconee Engineering Change process. The as-built modification has several unplugged openings in the outer pipe to ensure it cannot function as a pressure boundary until this Relief Request is approved. At that time threaded plugs can be installed to establish the outer pipe as the "repair" 1 pressure boundary.)

Ultrasonic data from the degraded portion of the 3" piping upstream of valve LPSW-30, indicated that the pitting corrosion wear rate was 0.004"/year. The encapsulation design welds the 8" end of an 8" x 6" Sch. 40, reducer around the 3" pipe were it connects to the 36" header. Thus the weld for this end of the encapsulation joins the 8" end (7.98" ID) of the reducer and the non-degraded 36" header creating a 2.24" margin around the 3.5" OD of the 3" pipe. Although there is no basis to assume that corrosion from the 3" pipe would migrate to the area of the weld on the 36" header, a conservative application of a 0.004"/year corrosion rate (as seen in the 3" pipe) to the 36" header and a safety factor of 10, projects that it would take over 50 years for the identified corrosion to reach the weld area. Also, a circumferential reinforcement, 3/8" thick and 3" wide, was installed around the 8" end of the encapsulation where it connects to the 36" header.

Note: There were no locations identified on the 36" pipe header less than the Duke pitting threshold used for screening purposes (66% of nominal pipe wall).

The other end of the encapsulation design is welded by joining the 3.5" end of a 6" x 3.5" reducer to the exterior of a flange coupling (the flange connects the 3" pipe to LPSW-30).

The flange and approximately 4' of upstream piping was installed in November, 2014, which results in a configuration that has 4' of new 3" pipe between the end weld and the degraded section of 3" pipe (see Figure 1 above).

RA1-4 Section 5.1, Item 5 of the relief request states, "A hydrostatic pressure test shall be performed in accordance with ASME Section Xl, 2007 edition with 2008 addenda, tWA-4540, IWA-5000 and IWD-5230 using an external pressurization source upon completion of the repair/replacement activity to confirm the leak-tight integrity of the modification and its connecting welds to the component pressure boundary."

(1) Confirm that only the outer pipe, not the existing pipe, will be hydrostatically tested.

Duke reply: The hydrostatic test has been performed as part of the design change modification. The cavity between the inner pipe and the outer pipe was filled with demineralized water and pressurized using an external pressure source to a hydrostatic test pressure of 105 psig while LPSW was in service. The average LPSW system pressure is 82 psig which results in an differential pressure across the 3" pipe of approximately 23 psid.

(2) Discuss how the hydro test will be conducted, including hold time, and the hydrostatic pressure and temperature of the fluid.

Duke reply: (See (1) above) Threaded vent and drain holes in the outer pipe was used to facilitate filling, pressurizing, and draining the cavity between the inner pipe and the outer pipe for the hydrostatic test. The hydrostatic test was conducted at a pressure of 105 psig, a fluid temperature of 64.70 F, and a hold time of 12 minutes.

Page 4 RAI Response re:

RAT Response 15-ON-OO1 re: 15-ON-001 Page 4

ONS-2015-108

Enclosure:

Response to Request For Additional Information (3) Discuss whether the hydro test of the outer pipe would damage the existing (inner) pipe if the existing pipe has wall thinning or a pinhole leak.

Duke reply: An evaluation using ASME Section VIII, Division 1, Section UG-28 (Thickness of Shells and Tubes Under External Pressure) was performed assuming thethinnest point identified in UT scanning as the wall thickness (0.038 in) for the entire pipe. The results demonstrated that, with the assumed degradation, the piping could withstand an external differential pressure of greater than 47 psi. As discussed in (1) above, the hydrostatic test only produced a differential pressure of approximately 23 psid.

(4) Discuss the minimum wall thickness in the existing pipe that would support a hydro test of the outer pipe.

Duke reply: See response to (3) above (5) What is the total length of the existing pipe that will be encapsulated?

Duke reply: Approximately 8'-6" of 3" piping is encapsulated, with approximately 4'-3" of that piping being newly installed in November 2014. Therefore, only 4'-3" of the encapsulated piping is degraded (see Figure 1 above).

RAI-5

Section 5.1, Item 6 of the relief request states, "Following pressure testing, sealant shall be installed into the encapsulation to inhibit corrosion that could result from any future through-wall defects in the encapsulated piping..."

(1) During the sealant injection, discuss whether the sealant pressing against a wall thinning location on the existing pipe would cause the wall to collapse. What would be the minimum wall thickness to prevent sealant crushing the wall of the existing pipe?

(2) Describe briefly the sealant (e.g., commercial name, main ingredients, and compatibility with the materials of construction of both pipes and the environment).

(3) Does sealant prevent leakage from a hole on the existing pipe? Describe the size of a hole in the existing pipe beyond which the sealant will not be able to prevent leakage.

Duke reply: Duke hereby withdraws the provision to install sealant as described in Section 5.1 of the Relief Request.

RAI-6

It appears that the sealant can only inhibit corrosion on the outside surface, not inside surface, of the existing pipe and the outer pipe.

(1) Discuss the consequence of the existing pipe having through-wall holes and discuss whether the sealant could fall into the existing pipe and block the coolant flow.

(2) Provide any operating experience of this type of encapsulation in the nuclear or non-nuclear industry.

Duke reply: Duke will not install sealant (See answer to RAI-5).

Page 5 RAI Response re:

RAT Response re: 15-ON-OO1 15-ON-001 Page 5

ONS-2015-108

Enclosure:

Response to Request For Additional Information

RAI-7

Discuss the inservice examinations of the outer pipe (examination method and how often). Confirm that the existing pipe will not be examined in the future because it is inaccessible.

Duke reply: Upon implementation of this relief request, the encapsulation boundary (the outer piping) will become the credited pressure retaining boundary for this portion of the system. Thus, the encapsulation boundary will be subject to inservice inspection in accordance with Table IWD-2500-1, Category D-B, which requires a system leakage test and accompanying VT-2 examination each inspection period. The piping internal to the encapsulation boundary will be inaccessible and will not be examined in the future because credit will no longer be taken for its pressure retaining function, thus, it will be outside the inservice examination requirements of ASME Section XI.

RAI-8

Discuss the welding of the encapsulation, e.g., weld material, welding process, pre-heat requirement, post-weld heat treatment, and the ASME Code requirements applicable to that welding.

Duke reply:

• The welding filler material was QA Condition 1 Welding Materials and meets the requirements of ASME Section II Part C and SEA 5.18.

• The new welds were installed using GTAW process and ER-70S-2 filler material.

• The new piping & plate material used was: SA-105 (Gr. WPB), A-106 (Gr. B), and A-36.

The existing piping material was A-106 (Gr. B) and A-105 (Gr. WPB), which are all category P1 materials per the applicable edition of ASME IX.

• The minimum pre-heat requirement was defined as 50°F for all P1 material. The material thickness does not exceed 1" in th.ickness, therefore pre-heat as defined in ASME B31.1, 2004, 131.4.2 does not apply.

• PWHT is not required due to the thickness of any member does not exceed 3/4" thick (Ref. ASME B31.1, 2004, Table 132, ASME B31.1, 2004).

• The ASME Code requirements for this weld are:

o] 3/16" maximum reinforcement (ref. table 127.4.2),

o] Visual inspection (ref. table 136.4, ASME B31 .1, 2004),

o] Duke Energy inspection procedures applicable are (NDE- 60D & QAL-16).

RAI-9

Section 5.1, Item 1 of the relief request states that the construction code is ASME B31.1-2007 edition. Item 4 in Section 5.1 states that a visual examination is performed based on ASME B31.1-2004. Section 1.1 states that the pipe was constructed to USAS B31.1-1967. Discuss why three different editions of B31.1 are referenced and to which edition of B31.1 should the design, repair, and examination of the encapsulation adhere.

Duke reply: Section 5.1 Item 1 refers to ASME B31 .1-2007 as the construction code for the design of the piping encapsulation. This code edition is the current code selected by Duke Energy to represent the Construction Code for present day construction/modifications. Use of more current editions in lieu of the original construction code is allowed by ASME Section XI IWA-4221(c).

Page 6 re: 15-ON-OO1 RAI Response RAI Response re: 15-ON-001 Page 6

ONS-2015-108

Enclosure:

Response to Request For Additional Information Section 5.1, Item 4 refers to the visual NDE examination of the welds. This exam is based on ASME B31.1-2004 because this is the Code edition incorporated into the Duke Energy NDE program for construction code NDE inspections of Oconee Duke Class F welding. The incorporation of this edition of the code for construction code applications is allowed by ASME Section Xl, IWA-4221(c).

Section 1.1 states the piping system was constructed to USAS B31.1-1 967 which represents the original construction code used at Oconee for Duke Class F (QA-1) piping.

In summary:

The original construction code is B31.1-1967. As allowed by ASME Section Xl, the encapsulation is procured and designed to B31 .1-2007 (in lieu of the original construction code), and Welding and Weld NDE requirements are performed per B31.1-2004 (in lieu of the original construction code).

RAI- 10 Describe how the flow of LPSWS water inside the encapsulated pipe will be sufficient to achieve the system's safety function for the most limiting failure of the 3-inch inner pipe.

Discuss how the control room operator will be alerted if the 3-inch pipe fails and the required coolant flow is reduced from the 36-inch header to valve LPSW-30. Also describe any corrective actions that operators may take to address low flow conditions in the affected section of LPSWS piping.

Duke Clarification: RAI-IO focuses on the relief request potential of flow reduction due to continued corrosion of the inner pipe. Note, there are two independent flow paths from the LPSW header to the MDEFW motor coolers (see Figure 1 above). These flow paths combine downstream of LPSW-30 (beyond the area affected by this Relief Request) and either flow path can supply adequate flow to the motor coolers.

Duke reply: Inadequate cooling flow to the Motor Driven Emergency Feedwater Pump (MDEFWP) motor coolers could potentially affect operability of the MDEFWPs. However, sufficient flow to the coolers can be supplied by either the LPSW-27 branch line or the LPSW-30 branch line. The LPSW operating procedure requires both flow paths from the LPSW header to the MDEFW Motor cooler supply line to be aligned by locking open valves LPSW-27 and LPSW-30. The Unit startup procedure also has operators verify the position of LPSW valves. If a flow reduction in the LPSW-30 branch line was to occur due to degradation of the 3" pipe, it is unlikely that flow through the LPSW-30 branch line would be reduced to a no-flow condition, but if the LPSW-30 branch line were to be totally blocked, the LPSW-27 branch line would still provide adequate flow to the MDEFWP Motor Coolers.

Thus, any potential effect on safety function caused by flow degradation upstream of LPSW-30 can be compensated by the LPSW-27 flow path.

Water flow is initiated to the motor cooler of a MDEFWP when it is started. Operations records the LPSW flowrate to each MDEFWP motor cooler during a Quarterly performance test. During those checks, flow to the motor cooler is typically >100gpm. If flow to the motor cooler goes below 30gpm (minimum design flow), the Operator Aid Computer (OAC) will alarm. The OAC also alarms on HI and HI-HI stator temperature for a MDEFWP. The alarm response guide directs the Operator to closely monitor pump parameters & check LPSW valve lineup.

Procedural valve alignment, performance testing of MDEFWPs, and OAC alarms all provide a means for the control room operators to be aware of reduced flow conditions to the motor coolers. However, reduced flow through the LPSW-30 branch line will have little effect on available flow to the motor coolers, due to the dual supply lines from the LPSW header, via LPSW-27 and LPSW-30.

RAI Response re: 15-ON-001 Page 7