GO2-24-102, Relief Requests for the Fifth Inservice Inspection Interval
| ML24323A191 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/18/2024 |
| From: | Hauger J Energy Northwest |
| To: | Office of Nuclear Reactor Regulation, Document Control Desk |
| References | |
| GO2-24-102 | |
| Download: ML24323A191 (1) | |
Text
Jeremey S. Hauger Columbia Generating Station P.O. Box 968, Mail Drop PE23 Richland, WA 99352-0968 Ph. 509-377-8727 jshauger@energy-northwest.com 10 CFR 50.55a GO2-24-102 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001
Subject:
COLUMBIA GENERATING STATION, DOCKET NO. 50-397 RELIEF REQUESTS FOR THE COLUMBIA GENERATING STATION FIFTH INSERVICE INSPECTION INTERVAL
Dear Sir or Madam:
Pursuant to 10 CFR 50.55a(z)(2), Energy Northwest hereby requests U.S. Nuclear Regulatory Commission approval of the attached two relief requests for the upcoming Fifth Inservice Inspection (ISI) Interval at Columbia Generating Station. Attachment 1 to this letter provides a comparison between the relief requests for the fourth ISI interval and the relief requests for the fifth ISI interval. The details of the 10 CFR 50.55a requests are included as Attachments 2 and 3.
Energy Northwest requests relief due to the determination that complying with the requirements would result in a hardship or unusual difficulty without a compensating increase in the level of quality and safety.
Approval of the relief requests are required by November 21, 2025. Once approved, the relief requests shall be implemented within 40 days.
There are no new commitments made in this submittal.
If there are any questions or if additional information is needed, please contact Mr. R. M.
Garcia, Licensing Supervisor, at 509-377-8463.
Executed this ____ day of November, 2024 Respectfully, Jeremy S. Hauger Vice President, Engineering
November 18, 2024 ENERGY NORTHWEST IA DocuSigned by:
~Jc~~
GO2-24-102 Page 2 of 2
- Comparison Between 4th Interval and 5th Interval Inservice Inspection Relief Requests : Relief Request Number 5ISI-04 : Relief Request Number 5ISI-03 cc:
NRC RIV Administrator NRC NRR Project Manager NRC Senior Resident Inspector/988C CD Sonoda - BPA/1399 EFSECutc.wa.gov - EFSEC E Fordham - WDOH R Brice - WDOH L Albin - WDOH
GO2-24-102 Page 1 of 1 Comparison Between 4th Interval and 5th Interval Inservice Inspection Relief Requests 4th Interval Relief Request Number 5th Interval Relief Request Number Comments 4ISI-01 N/A Relief Request for alternative examination methodology as allowed by GL 98-05 for Code Category B-A, Item Number B1.11. This request expired in December 2023, and is superseded by relief request 4ISI-11 (5ISI-01).
4ISI-02 N/A Code Case N-795 is an alternative to IWB-5221(a) following repair/replacement activities on Class 1 system components excluding the reactor vessel. Relief Request 4ISI-02 will expire as Code Case N-795 is incorporated into 2019 Edition of the ASME BPV Code,Section XI, subparagraph IWB-5221(d).
4ISI-03 N/A Temporary relief for IWA-4150(b) to use ISI-3 until January 31, 2016. Temporary relief is no longer required.
4ISI-04 N/A Use of Code Case N-702; Alternative requirements for nozzle inner radius and nozzle to shell welds. Code Case N-702 and IWB-2500(f) are not available to Columbia in its period of extending operation.
4ISI-05 5ISI-04, Relief Request Number 5ISI-04 4ISI-06 N/A Code Case N-666-1 for weld overlay of Class 1,2, and 3 socket welded connections. Relief Request 4ISI-06 will expire as the use of Code Case is conditionally accepted in R.G. 1.147.
4ISI-07 5ISI-03, Relief Request 5ISI-03 4ISI-08 N/A Code Case N-885-1 allows an alternative to VT-3 visual examination of accessible areas of reactor. Relief Request 4ISI-09 is not needed in the new interval to implement this Code Case as it is accepted in RG 1.147, Revision 21.
4ISI-09 5ISI-02 Relief Request 4ISI-09 for alternate examination of Feedwater nozzles is approved to for use up to the end of Columbias period of extended operation ending on December 12, 2043. (ADAMS Accession No. ML21096A048) 4ISI-10 N/A Relief Request 4ISI-10 to use subparagraph IWA-4540(b) of the 2017 Edition of the ASME BPV Code,Section XI, will expire. IWA-4540(b) of the 2019 Edition of the ASME BPV Code,Section XI, will be Follow in the 5th interval of Columbias ISI program.
4ISI-11 5ISI-01 Relief Request 4ISI-11 for alternate examination of the Reactor Vessel Welds is approved for use to the end of Columbias period of extended operation ending on December 12, 2043. (ADAMS Accession No. ML23143A120)
GO2-24-102 Page 1 of 7 Relief Request Number 5ISI-04 Alternative Test Method for RPV Leak Detection Line Proposed Alternative In Accordance with 10 CFR 50.55a(z)(2)
Hardship or Unusual Difficulty without Compensating Increase in Level of Quality and Safety
- 1. ASME Code Component(s) Affected
==
Description:==
Reactor Pressure Vessel (RPV) head flange leak-off line originating from reactor vessel nozzle N-17 ASME Code Class:
Class 1 and Class 2 Examination Category:
B-P (all pressure retaining components) and C-H (all pressure retaining components)
Item Number:
B15.20 and C7.10 Components Affected:
Nominal Pipe Size NPS 1 carbon steel (SA-106, Gr B) leak off piping and fittings (SA-105, Gr II) from RPV nozzle N17 up to and including main steam valves MS-V-14 and MS-V-13 and NPS 3/4 (SA-106 Gr B) branch piping up to and including valve MS-V-764 and MS-PS-34.
2. Applicable Code Edition and Addenda
The Columbia Generating Station (Columbia) Inservice Inspection (ISI) fifth interval American Society of Mechanical Engineers (ASME)Section XI Code of Record is the 2019 Edition.
3. Applicable Code Requirements
System Leakage Test of Class 1 pressure retaining components per Table IWB-2500-1, Examination Category B-P, Item No. B15.20. As referenced in Table IWB-2500-1, IWB-5220, System Leakage Test, subparagraph IWB-5222(b) states that the Class 1 pressure-retaining boundary which is not pressurized when the system valves are in the position required for normal reactor startup shall be pressurized and examined at or near the end of the inspection interval.
System Leakage Test of Class 2 pressure retaining components per Table IWC-2500-1, Examination Category C-H, Item No. C7.10; as referenced in Table IWC-2500-1, IWC-5220, System Leakage Test, subparagraph IWC-5221(b) states that for components that are not operated routinely, the leakage tests shall be conducted at the system pressure developed during a test conducted to verify system operability (e.g., to
GO2-24-102 Page 2 of 7 demonstrate system safety function or satisfy technical specification surveillance requirements). Table IWC-2500-1 specifies a frequency of once per period and IWA-5246 specifies the methodology for testing the reactor vessel head flange seal leak detection line.
4. Reason for Request
At Energy Northwest the RPV flange seal leak detection piping is ASME Class 1 up to the equipment drain isolation valve MS-V-13 and the instrument isolation valve MS-V-753. The piping is ASME Class 2 from the instrument isolation valve (MS-V-753) up to the test connection valve MS-V-764 (See Figure 2). The RPV flange seal leak detection piping is separated from the reactor pressure by one passive membrane, which is an O-ring, located on the vessel flange. A second O-ring is located on the opposite side of the tap in the vessel flange (See Figure 1). This piping is required during plant operation in order to detect failure of the inner flange seal O-ring. Failure of the O-ring would result in the annunciation of an alarm in the Control Room via pressure switch MS-PS-34 (See Figure 2). Failure of the inner O-ring is the only condition under which this line is pressurized. Therefore, the line is not expected to be pressurized during the system pressure test following a refueling outage.
The configuration of this piping precludes system pressure testing while the vessel head is removed because the configuration of the vessel tap, coupled with the high-test pressure requirement, prevents the tap in the flange from being temporarily plugged or connected to other piping. The opening in the flange is smooth walled, making the effectiveness of a temporary seal very limited. Failure of this seal could possibly cause ejection of the device used for plugging or connecting to the vessel.
The configuration also precludes pressure testing with the vessel head installed because the seal prevents complete filling of the piping, which has no vent available.
The top head of the vessel contains two grooves that hold the O-rings. The O-rings are held in place by a series of retainer clips that are housed in recessed cavities in the flange face. If a pressure test was performed with the head on, the inner O-ring would be pressurized in a direction opposite to what it would see in normal operation. This test pressure would result in a net inward force on the inner O-ring that would tend to push it into the recessed cavities that house the retainer clips. The thin O-ring material would very likely be damaged by this inward force.
Purposely failing or not installing the inner O-ring in order to perform a pressure test would require replacing the new outer and possibly the new inner O-ring each time the test is conducted. This would result in additional time needed during the outage and additional radiation exposure to personnel associated with the removal and reinstallation of the RPV head.
It is possible to pressurize the Class 2 portion only by closing MS-V-753 and pressurizing with an external source at the test connection point. The piping for this portion is less than 2 feet and constructed of 3/4 inch piping. When this task was performed in 2015 the total dose received was 64 mrem and no leakage was reported.
GO2-24-102 Page 3 of 7 Performance of this task each inspection period in accordance with Table IWC-2500-1 Category C-H, Item C7.10 would impose more dose than performing a combined Class 1 and Class 2 examination once at or near the end of the interval in accordance with this request.
5. Proposed Alternative and Basis for Use
In lieu of the pressure requirements of IWB-5222(b) & IWC-5221(b), Energy Northwest proposes to perform a VT-2 visual examination with the affected components subject to static pressure head with the RPV head removed and the refueling cavity filled to its normal refueling water level for at least four (4) hours. The static head developed with the leak-off lines filled with water will allow for detection of pressure boundary failures.
The high point of the leak-off-line is at nozzle N-17 located on the underside of the RPV flange. The top of the RPV flange is at elevation 583.1 feet and the flange thickness is 26 inches (2.2 feet). Nozzle N-17 originates at elevation 580.9 feet (583.1 - 2.2). Per procedure the refueling cavity is filled to the fuel pool level during refueling outages.
Water level is maintained in the fuel pool above the alarm level of 605.4 feet. Therefore, the minimum head pressure in the leak-off line is 24.5 feet (605.4 - 580.9) of water.
This proposed test methodology is identical to that presented in paragraph IWA-5246 of ASME Section XI (Reference 1). However, Energy Northwest is proposing a relief request because of Columbias configuration of both Class 1 and Class 2 leak-off piping that are isolated by the interior O-ring. Under the Code, Energy Northwest would need to perform the inspection on the Class 2 piping each inspection period and the Class 1 piping once per interval. Instead, Energy Northwest proposes to perform this test once at or near the end of the interval for both the Class 1 and Class 2 portions of the line.
Testing once per interval is consistent with IWB-5222(b) requirements and reduces the dose received during testing of the Class 2 portion.
Prior to performance of the VT-2 examination, Energy Northwest will ensure the leak-off lines are clear of air by having Operations fill and vent the line by opening valves MS-V-753 and MS-V-14 and closing valve MS-V-13. Additionally, a prerequisite in the work instructions requires the performer to verify that flood-up of the refuel cavity is completed and the leak-off lines are vented and filled for at least four hours prior to beginning the examination.
The leak-off piping exits the RPV flange at the 0-degree azimuth just above the ladder to the 568 feet elevation platform. The line exits the RPV flange at the N-17 nozzle which is behind a 40-inch x 42-inch removable insulation panel. From nozzle N-17 to the first elbow is approximately 22 inches with the first elbow six inches below the top of the access panel. The elbow directs the piping out through the insulation panel and away from the RPV into the containment volume. From there the piping extends approximately 20 feet around the RPV to pressure switch MS-PS-34 near the 270-degree azimuth. Access is available all the way around the RPV at this level so a VT-2 examination can be performed on the leak-off piping for evidence of leakage up to the ASME Section XI Code boundary valves. There is no other insulation on the leak-off-line except for the N-17 insulation panel. The piping is at approximately 579 feet
GO2-24-102 Page 4 of 7 elevation. An averaged sized individual at the platform at elevation 568 feet will be able to examine the piping using standard VT-2 tools such as mirrors and binoculars as needed. In the event portions of the pipe are obstructed from view, the examiner will look for indications of leakage on adjacent piping and surrounding area per IWA-5241 requirements. If signs of leakage are observed in the areas surrounding the N-17 insulation panel, the panel will be removed for further examination of the leak-off piping.
Energy Northwest performs a VT-2 inspection of the Class 1 portion of the head flange leak-off line each refueling outage in accordance with IWB-5222(a). A review of work order history, condition reports and Operations Logs shows no record of Columbia ever having a reactor pressure vessel flange O-ring leakage event or leakage in the leak-off piping. In July of 1992 there was an inadvertent pressure switch alarm annunciation from MS-PS-34 during start-up caused by residual water in the leak-off line that had flashed to steam. The calibration procedure was revised to include draining the line.
Should the inner O-ring leak during the operating cycle, it will be identified through the alarm of a pressure switch in the main control room. Upon receiving an alarm, operator actions will monitor drywell floor drain leakage per site procedures. If drywell leakage is indicated the station will monitor drywell temperature and pressure, containment radiation monitors located in the control room, and drywell fission products. If monitoring actions indicate Reactor Coolant System (RCS) leakage, operators are directed per the annunciator response procedure to Technical Specification 3.4.5, RCS Operational Leakage. Similarly, should the inner O-ring leak during the operating cycle and a through wall leak of the reactor vessel flange leak-off piping exist, leakage will be detected in the same manner described above and appropriate actions will be taken per Technical Specification 3.4.5. Since there is reasonable assurance that the proposed alternate examination will detect gross indications of leakage should any exist from this piping, Energy Northwest requests authorization to use the proposed alternative pursuant to 10 CFR 50.55a(z)(2) on the basis that compliance with the specified requirement would result in hardship or difficulty without a compensating increase in the level of quality and safety.
6. Duration of Proposed Alternative
The duration of this request is for the fifth inservice inspection interval beginning December 13, 2025, and ending December 12, 2037. Energy Northwest intends to implement Code Case N-921 for the fifth inservice inspection interval which will allow an alternative 12-year inspection interval duration. This Code Case is conditionally acceptable in Regulatory Guide 1.147, Revision 21.
GO2-24-102 Page 5 of 7
7. Precedents
7.1 The following precedents pertain to approved relief requests for leak-off lines classified as ASME Code Class 1 using Code Case N-805:
(a) Columbia submitted Inservice Inspection (ISI) Program Request 3ISI-15,
[ML14077A173] on March 7, 2014, requesting use of Code Case N-805 for the Class 1 leak-off line. This request was supplemented by Response to Request for Additional Information for Relief Request 3ISI-15 [ML14245A058]. This request was approved under [ADAMS Accession No. ML15037A005] on February 13th, 2015.
(b) Columbia submitted Inservice Inspection (ISI) Program request 4ISI-05, February 17th, 2016, requesting use of Code Case N-805. This request was approved under [ADAMS Accession No. ML17018A082] on January 24th, 2017.
(c) Millstone Power Station, Unit No. 3 - Issuance of Relief Request IR-3-11 Regarding Use of American Society of Mechanical Engineering Code,Section XI, 2004 Edition (TAC No. ME1263); April 29, 2010; Docket No. 50-423 [ADAMS Accession No. ML101040042].
(d) Limerick Generating Station, Units 1 and 2, Evaluation of Relief Requests RR-33, RR-34 and RR-35, Associated with the Second In-service Inspection Interval (TAC Nos. MD8071, MD8073, MD8074, MD8075, and MD8076);
January 27, 2009; Docket Nos. 50-352 and 50-353 [ADAMS Accession No. ML090060218].
(e) North Anna Power Station, Unit No's. 1 and 2 Re: ASME Code Third 10-year ISI Program. (TAC No's MC5588, MC5589, MC5590, MC5591, MC5592, MC5593, MC5594, MC5595, MC5599 and MC5600); February 9, 2006; Docket Nos. 50-338 and 50-339 [ADAMS Accession No. ML060450517].
7.2 The following precedents pertain to approved relief requests for leak-off lines classified as ASME Code Class 2:
(a) Vermont Yankee, Vermont Yankee Nuclear Power Station - Relief Request ISI-PT-02: Fourth 10-Year Inservice Inspection Interval, approved by the NRC in a letter dated March 1, 2013 [ADAMS Accession No. ML13055A009].
(b) Dresden, Units 2 and 3, Dresden Nuclear Power Station, Units 2 and 3 -
Safety Evaluation in Support of Request for Relief Associated with the Fifth 10-Year Inservice Inspection Interval Program, Enclosure 3 approved by the NRC in a letter dated September 30, 2013 [ADAMS Accession 1\\10. ML13258A003].
GO2-24-102 Page 6 of 7
- 8. References
- 1. American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, Rules for Inspection and Testing of Components of Light-Water-Cooled Plants - Division 1, 2019 Edition
GO2-24-102 Page 7 of 7 Figure 1 Detail of RPV Head Flange Leak Detection Tap Figure 2 RPV Seal Leak-off Detection Line Schematic
0.12" min diameter hole----1/2-I nner O-ring 0.50" min dia.meter hole through flange.
1 inch pipe.
r.,
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To E'quiflmvi,t bl!'a.in Closure Hea.d Sys~.l!tl,
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GO2-24-102 Page 1 of 7 Relief Request Number 5ISI-03 Standby Liquid Control System (SLC) piping Proposed Alternative in Accordance with 10 CFR 50.55a (z)(2)
Hardship or Unusual Difficulty Without Compensating Increase in Level of Quality or Safety
- 1. ASME Code Component(s) Affected Code Class:
2
Reference:
American Society of Mechanical Engineers (ASME)Section XI, IWA-5213(a)(2)
Examination Category:
C-H Item Number: C7.10 Components affected:
Standby Liquid Control (SLC) system piping from SLC pumps 1A and 1B to valves SLC-V-3A and SLC-V-3B and to relief valves SLC-RV-29A and SLC-RV-29B. The SLC system consists of two loops, A and B. The scope of this request for each loop consists of approximately 5-1/2 feet of 1-inch and 1-1/2-inch schedule 80S SA 312 TP304 pipe, one 1-inch relief valve, one 1-1/2-inch check valve, and one 1-1/2-inch gate valve. All components are not insulated. Further details are shown on the attached drawings.
2. Applicable Code Edition and Addenda
The Columbia Generating Station (Columbia) Inservice Inspection (ISI) fifth interval American Society of Mechanical Engineers (ASME)Section XI Code of Record is the 2019 Edition.
3. Applicable Code Requirement
The applicable ASME Section XI Code requirement is contained in Article IWA-5000, System Pressure Tests, Sub-Article IWA-5200, System Test Requirement, IWA-5213, Test Condition Holding Time, (a)(2), For Class 2 [Table IWC-2500-1 (C-H)]
and Class 3 [Table IWD-2500-1 (D-B)] components in standby systems (or portions of standby systems) that are not operated routinely except for testing, a 10 min holding time is required after attaining test pressure.
The ASME Section XI system pressure test of the SLC pump discharge piping is performed at Columbia by two methods. The system downstream of valves SLC-V-3A
GO2-24-102 Page 2 of 7 and SLC-V-3B uses a system hydrostatic test to pressurize the system. After a ten-minute hold time the VT-2 visual examination is performed. Gate valves SLC-V-3A and SLC-V-3B are used to isolate the portion of the system upstream of the pumps (design pressure 150 psig) from the higher downstream pressure (design pressure 1400 psig). The remaining portion of the discharge piping from the pumps to valves SLC-V-3A and SLC-V-3B is pressurized using the SLC pumps SLC-P-1A and SLC-P-1B since no vent or drain lines or test connections are available to connect a pump for a hydrostatic test.
- 4.
Reason for Request
This 10 CFR 50.55a relief request is to eliminate the 10-minute hold time requirement of IWA-5213(a)(2) for the small segment of the SLC system that cannot be pressurized using a system hydrostatic test. Use of a system hydrostatic test would require disconnecting pumps SLC-P-1A and SLC-P-1B and installing blind flanges with fittings which is considered impractical. In lieu of this major maintenance activity, a system modification would be required to install a test connection(s) on the affected portion of the system.
Since performing a system hydrostatic test is impractical, Columbia uses the positive displacement pumps, SLC-P-1A and SLC-P-1B, during their operability test to attain a pressure to support the VT-2 examination. There is a small volume of fluid circulated through 1-inch, 1-1/2-inch, 3-inch, and 4-inch nominal pipe size pipe and a 210 gallon capacity test tank during the operability test. Since this small volume rapidly heats up during the operability test, the pumps are run for approximately 3 to 5 minutes. This prevents erratic pump discharge and chattering of relief valves SLC-RV-29A and SLC-RV-29B. Chattering these relief valves has caused damage to the sealing surfaces in the past. Investigation of these relief valve failures resulted in the pump operability procedure changes in 1996 to limit the pump run time.
The burden caused by compliance to the 10-minute hold time is the higher potential of the relief valves being damaged so that they will not meet their functional requirements (set point) requiring repair or replacement of the valves. Energy Northwest experience with SLC-RV-29A and SLC-RV-29B set point failures is documented in References 1 and 2.
- 5.
Proposed Alternative and Basis for Use Pursuant to 10 CFR 50.55a(z)(2), relief is requested to eliminate the 10-minute hold time requirement of IWA-5213 for the small segments of the SLC system that cannot be pressurized by a system hydrostatic test.
The proposed alternative to the 10-minute hold time required by IWA-5213(a)(2) is to perform the VT-2 examination when SLC-P-1A or SLC-P-1B is started for its respective pump operability test. The pump operability test runs each pump for approximately 3-5
GO2-24-102 Page 3 of 7 minutes. The VT-2 examiner will continually observe each section of piping during the entire time the pump is operating for the pump operability test. The system pressure rapidly increases to the 1240 psig operating pressure when the pump starts. The high VT-2 test pressure would reveal any through wall discontinuities rapidly in the uninsulated piping, thus providing reasonable assurance of structural integrity without implementing the 10-minute hold time required by IWA-5213(a)(2).
- 6.
Duration of Proposed Alternative The duration of this request is for the fifth inservice inspection interval beginning December 13, 2025, and ending December 12, 2037. Energy Northwest intends to implement Code Case N-921 for the fifth inservice inspection interval which will allow an alternative 12-year inspection interval duration. This Code Case is conditionally acceptable in Regulatory Guide 1.147, Revision 21.
- 7.
Precedents There are three precedents for this request in the Nuclear Regulatory Commission Safety Evaluations approving Columbia Generating Station ISI second, third, and fourth 10-year interval relief requests 2ISI-29, 3ISI-05, and 4ISI-07 transmitted by References 3, 4, and 5 respectively.
- 8.
References
- 1.
D. K. Atkinson, Energy Northwest, to NRC, Request to Implement 2ISI-29 Addressing ASME Section XI, IWA-5213, Test Condition Holding Times, for the Second inservice Inspection Interval, dated November 22, 2004
[ADAMS Accension Number: ML043350363]
- 2.
W. S. Oxenford, Energy Northwest, to NRC, Submittal of the Third Ten-Year Interval Inservice Inspection Program Plan and 10 CFR 50.55a Requests 3ISI-01 through 3ISI-07 for Columbia Generating Station, dated December 15, 2005 [ADAMS Accension Number: ML053620391]
- 3.
Robert A Gramm, Office of Nuclear Reactor Regulation, to J. V. Parrish, Chief Executive Officer, Energy Northwest, Columbia Generating Station -
American Society of Mechanical Engineers (ASME) Inservice Inspection Program Relief Requests 2ISI-29 and 2ISI-30, Subsequent ASME Section XI Edition and Addenda for Pressure Testing (TAC NOS. MC5189, MC5190), dated May 17, 2005 [ADAMS Accension Number:
ML050870348]
GO2-24-102 Page 4 of 7
- 4.
David Terao, Office of Nuclear Reactor Regulation, to J. V. Parrish, Chief Executive Officer, Energy Northwest, Columbia Generating Station - Relief Request No. 3ISI-05 for the Third 10-year Inservice Inspection Interval RE:
Hold Time Prior to VT-2 Examination of Standby Liquid Control System (TAC NO. MD1168), dated March 19, 2007 [ADAMS Accension Number:
ML070650661]
- 5.
Robert J. Pascarelli, Office of Nuclear Reactor Regulation, to Mark E.
Reddemann, Chief Executive Officer, Energy Northwest, Columbia Generating Station - Relief Request for Alternative 4ISI-07 to the Fourth 10-year Inservice Inspection Program Interval (CAC NO. MF7648), dated February 16, 2017 [ADAMS Accension Number: ML17046A507]
GO2-24-102 Page 5 of 7
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