GO2-24-003, Relief Requests for the Columbia Generating Station Fifth Ten-Year Interval Inservice Testing

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Relief Requests for the Columbia Generating Station Fifth Ten-Year Interval Inservice Testing
ML24029A071
Person / Time
Site: Columbia 
Issue date: 01/29/2024
From: Hauger J
Energy Northwest
To:
Office of Nuclear Reactor Regulation, Document Control Desk
References
GO2-24-003
Download: ML24029A071 (1)
v • d • e


Text

Jeremy S. Hauger Columbia Generating Station P.O. Box 968, PE30 Richland, WA 99352-0968 509.377.8727 jshauger@energy-northwest.com GO2-24-003 10 CFR 50.55a 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 TEN-YEAR INTERVAL INSERVICE TESTING

Dear Sir or Madam:

Pursuant to 10 CFR 50.55a(z)(1), 10 CFR 50.55a(z)(2), and 10 CFR 50.55a(f)(5)(iii),

Energy Northwest hereby requests U.S. Nuclear Regulatory Commission (NRC) approval of the attached seven relief requests for the upcoming Fifth Ten-Year Inservice Testing (IST) Program at Columbia Generating Station (CGS). Attachment 1 to this letter provides a comparison between the relief requests for the fourth ten-year interval and the relief requests for the fifth ten-year interval. The details of each 10 CFR 50.55a request are included as Attachments 2 through 8.

Energy Northwest requests relief due to alternatives providing an acceptable level of quality and safety, 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, and impracticality of conformance with certain IST Code requirements.

Approval of the relief requests is requested by November 1, 2024. Approval of the relief requests is required prior to the start of the new ten-year IST interval, beginning December 13, 2024. Once approved, the relief requests shall be implemented within 40 days.

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January 29, 2024 ENERGY NORTHWEST

GO2-24-003 Page 2 of 2 There are no regulatory commitments made in this submittal.

If you have any questions or require additional information, please contact Mr. R. M.

Garcia at 509-377-8463.

Executed this ______ day of ___________, 2024.

Respectfully, Jeremy S. Hauger Vice President, Engineering : Comparisons Between 4th Ten-Year Interval and 5th Ten-Year Interval Relief Requests : Relief Request 5IST-01 : Relief Request 5IST-02 : Relief Request 5IST-03 : Relief Request 5IST-04 : Relief Request 5IST-05 : Relief Request 5IST-06 : Relief Request 5IST-07 cc:

NRC RIV Regional 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

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DocuSigned by:

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GO2-24-003 Page 1 of 1 Comparisons Between 4th Ten-Year Interval and 5th Ten-Year Interval Relief Requests 4th Ten-Year Interval Relief Request Number 5th Ten-Year Interval Relief Request Number Comments RG01 N/A Code Case OMN-20 has been incorporated into the 2017 Edition and subsequent Editions as ISTA-3170. This Code Case eliminates the uncertainty of implementing Technical Specification grace for IST and, in addition to the normal IST frequency grace, allows for grace with intervals greater than 2 years.

RG01 is not needed in the new interval to implement this Code Case RP01 RP01, Relief Request 5IST-01 RP02 N/A Code Case OMN-16 allows for the use of a reference pump curve rather than a single reference value. This Code Case may be used for certain pumps if needed.

RP02 is not needed in the new interval to implement this Code Case, as it has been deemed acceptable in Regulatory Guide (RG) 1.192, Revision 4.

RP03 N/A Code Case OMN-16 allows for the use of a reference pump curve rather than a single reference value. This Code Case may be used for certain pumps if needed.

RP03 is not needed in the new interval to implement this Code Case, as it has been deemed acceptable in RG 1.192, Revision 4.

RP04 RP02, Relief Request 5IST-02 RP05 RP03, Relief Request 5IST-03 RP06 N/A Code Case OMN-19 has been incorporated into the 2012 and subsequent Editions as shown in Tables ISTB-5121-1, ISTB-5221-1, ISTB-5321-1, & ISTB-5321-2.

RP06 is not needed in the new interval to implement this Code Case.

RV01 RV01, Relief Request 5IST-04 RV02 RV02, Relief Request 5IST-05 RV03 RV03, Relief Request 5IST-06 RV04 RV04, Relief Request 5IST-07

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GO2-24-003 Page 1 of 4 Relief Request 5IST-01 RP01: Testing of Pump Discharge Pressure In Lieu of Differential Pressure Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Components Affected

2. Applicable Code Edition and Addenda

American Society of Mechanical Engineers (ASME) Code for Operation and Maintenance of Nuclear Power Plants (OM Code), 2020 Edition, no addenda.

3. Applicable Code Requirements

ISTB-5210, Baseline Testing, Table ISTB-3000-1, Subparagraph (a) states in part, In systems where resistance can be varied, flow rate and differential pressure shall be measured ISTB-5220, Inservice Testing, Subsection ISTB-5221, Group A Test Procedures, Subparagraph (b) states in part, The differential pressure shall then be determined and compared to its reference value.

4. Reason for Request

There are no inlet pressure gauges installed in the inlet of these vertical line shaft centrifugal pumps, making it impractical to directly measure inlet pressure for use in determining differential pressure for the pump.

5. Proposed Alternative and Basis for Use

Pump discharge pressure will be recorded during the testing of these pumps. Code Acceptance Criteria will be based on discharge pressure instead of differential pressure as specified in Table ISTB-5221-1, Vertical Line Shaft Centrifugal Pump Test Acceptance Criteria. The effect of setting the Code Acceptance Criteria on discharge pressure instead of differential pressure as specified in the Code will have no negative impact on detecting pump degradation.

Pump Code Class Pump Group P&ID Dwg. No.

System(s)

SW-P-1A 3

A M524, SH 1 Standby Service Water SW-P-1B 3

A M524, SH 2 Standby Service Water HPCS-P-2 3

A M524, SH 1 Standby Service Water, High Pressure Core Spray

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GO2-24-003 Page 2 of 4 5.1 Pumps SW-P-1A, SW-P-1B, and HPCS-P-2 are vertical line shaft centrifugal pumps which are immersed in their water source and have no suction line which can be instrumented.

5.2 Surveillance Requirement (SR) 3.7.1.1 in CGS Technical Specifications (TS) specifies the minimum allowable spray pond level to assure adequate net positive suction head and ultimate heat sink capability.

5.3 The difference between allowable minimum and overflow pond level is only 21 inches of water or 0.8 pounds per square inch (psi). This small difference will not be significant to the program and suction pressure will be considered constant. Administratively, the pond level is controlled within a 9 inch (0.33 psi) band. Discharge pressure trend data for the previous two years is shown in the table below for all three pumps.

The discharge pressure for SW-P-1A and SW-P-1B for the past two years has ranged from 213.71 to 220.33 psig (pounds per square inch gauge), which results in the 0.33 psig suction pressure being less than 0.2% of discharge pressure. Pump HPCS-P-2 discharge pressure variation for the past two years has ranged from 59.44 to 61.75 psig, which results in the 0.33 psig suction pressure variation being less than 0.6% of discharge pressure. This very small suction pressure variation is insignificant and does not adversely impact Energy Northwests ability to monitor for pump degradation.

HPCS-P-2 SW-P-1A SW-P-1B Date Discharge Pressure (psig)

Date Discharge Pressure (psig)

Date Discharge Pressure (psig) 3/27/2021 60.00 8/3/2021 217.30 3/17/2021 218.86 7/3/2021 59.70 11/2/2021 218.67 6/22/2021 216.28 10/2/2021 60.50 2/10/2022 220.33 9/21/2021 213.94 1/1/2022 61.50 5/5/2022 219.00 12/21/2021 216.59 4/2/2022 60.20 6/7/2022 218.01 3/24/2022 217.25 7/2/2022 59.44 8/1/2022 216.27 6/23/2022 215.19 9/28/2022 61.75 11/7/2022 218.00 9/20/2022 213.71 12/31/2022 61.50 2/8/2023 220.31 12/29/2022 219.29 4/2/2023 61.00 5/4/2023 218.80 3/29/2023 218.80 7/1/2023 60.50 8/11/2023 216.84 6/24/2023 216.40 9/30/2023 60.97 10/04/2023 216.27 9/20/2023 214.98 5.4 Acceptable flow rate and discharge pressure will suffice as proof of adequate suction pressure.

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GO2-24-003 Page 3 of 4 Total Head Discharge Head Suction Head Total Head 5.5 These pumps operate with a suction lift. The maximum elevation of spray pond level is 434 feet, 6 inches and minimum elevation of discharge piping for these pumps is 442 feet 5/8 inches. Thus, discharge pressure for these pumps will always be lower than the calculated differential pressure for the entire range of suction pressures. Therefore, acceptance criteria based on discharge pressure is conservative. This is further illustrated below.

Differential pressure is defined as discharge pressure minus suction pressure.

In the case of a pump with suction lift, the suction pressure is negative; thus:

P = Pd - (-Ps)

P = Pd + Ps This concept is more easily understood when head is used instead of pressure.

Case 1: Suction Head Case 2: Suction Lift The ASME Code refers to differential pressure instead of total head since differential pressure is required to be measured. However, most literature on pumps deals with hydraulic parameters in terms of head and flow. In Case 1:

Total Head = Discharge Head - Suction Head But in Case 2, for the Service Water pumps, Total Head = Discharge Head + Suction Lift.

When one converts head to pressure, the equivalent formula for differential pressure would be:

P(psi) = Pd(psi) + 0.431(psi/ft) x (ELpump(ft) - Elwaterlevel(ft))

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Discharge Head Suction Lift

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GO2-24-003 Page 4 of 4 Since pump discharge pipe elevation for these pumps is always more than spray pond water level, discharge pressure is always less than the calculated differential pressure.

6. Duration of Proposed Relief Alternative The proposed alternative will be utilized for the entire fifth ten-year IST Program interval, which begins on December 13, 2024, and ends on December 12, 2034.
7. Precedent This relief was previously granted for the CGS fourth ten-year IST Program interval.

Approval of relief was documented in NRC letter to CGS, Columbia Generating Station - Requests for Relief NOs. RG01, RP01, RP02, RP03, RP04, RP05, RP06, RV01, RV02, RV03, and RV04 for the Fourth 10-Year Inservice Testing Interval (TAC NOs. MF3847, MF3848, MF3849, MF3851, MF3852, MF3853, MF3854, MF3855, MF3856, MF3857, and MF3858), dated December 9, 2014 (ADAMS Accession Number ML14337A449).

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GO2-24-003 Page 1 of 3 Relief Request 5IST-02 RP02: Alternate Discharge Pressure Instrumentation Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Components Affected

2. Applicable Code Edition and Addenda

ASME OM Code, 2020 Edition, no addenda.

3. Applicable Code Requirements

ISTB-3510, General, paragraph (b), Range, subparagraph (1) states, The full-scale range of each analog instrument shall be not greater than three times the reference value.

4. Reason for Request

Installed test gauges used to measure the pump discharge pressure, which is used to determine differential pressure, do not meet the OM Code range requirements.

Residual Heat Removal (RHR) and High Pressure Core Spray (HPCS) pumps discharge pressure instruments (RHR-PT-37A, RHR-PT-37B, RHR-PT-37C, and HPCS-PT-4) exceed, or may exceed (dependent upon measured parameters), the Code allowable range limit of three times the reference value. An alternative is proposed for Group A, and Group B inservice tests only. Temporary test gauges meeting the OM Code requirements shall be used for comprehensive and preservice tests.

5. Proposed Alternative and Basis for Use

During Group A or Group B pump inservice testing, pump discharge pressure which is used to determine differential pressure shall be measured by respective Transient Data Acquisition System (TDAS) points listed below for each pump. TDAS data averages 100 readings with a reading taken each second.

Pump Code Class Pump Group P&ID Dwg. No.

System RHR-P-2A 2

A M521, SH 1 Residual Heat Removal RHR-P-2B 2

A M521, SH 1 RHR-P-2C 2

A M521, SH 1 HPCS-P-1 2

B M520 High Pressure Core Spray

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GO2-24-003 Page 2 of 3 5.1 ISTB-3510(a) and ISTB-3510(b)(1) specify both accuracy and range requirements for each instrument used in measuring pump performance parameters. The purpose of instrument requirements is to ensure that pump test measurements are sufficiently accurate and repeatable to permit evaluation of pump condition and detection of degradation. Instrument accuracy limits the inaccuracy associated with the measured test data. Thus, higher instrument accuracy lowers the uncertainty associated with the measured data. The purpose of the OM Code range requirement is to ensure reading accuracy and repeatability of test data.

5.2 Since the TDAS data is being obtained to an accuracy of +/- 1% of full scale, it consistently yields measurements more accurate than would be provided by instruments meeting the OM Code instrument accuracy requirement of +/- 2% of full scale and range requirement of three times the reference value. Equivalent accuracy being obtained by TDAS measurements is calculated in the table below.

  • The above table reflects latest reference values as specified in the implementing procedures. This table will not be updated to reflect small changes in future reference values. Procedure reference value for HPCS-P-1 is differential pressure.

Thus, the range and accuracy of TDAS instruments being used to measure pump discharge pressure result in data measurements of higher accuracy than that required by the OM Code and thus will provide reasonable assurance of pump operational readiness. It should also be noted that the TDAS system averages many readings, therefore giving a significantly more accurate reading than would be obtained by using the averaging technique as allowed by ISTB-3510(d) on visual observation of a fluctuating test gauge.

5.3 The range of the pressure transmitters (PT) used for these applications were selected to bound the expected pump discharge pressure range during all normal and emergency operating conditions (the maximum expected discharge pressure for the RHR and HPCS pumps is approximately 450 psig and 1,400 psig respectively). However, during inservice testing the pumps are tested at full flow, resulting in lower discharge pressures than the elevated discharge pressure that can occur during some operating conditions. For this reason, the Pump Test Parameter Instrument I.D.

Range (PSIG)

  • Ref.

Value (PSIG)

Instrument Loop Accuracy Equivalent Code Accuracy RHR-P-2A Discharge Pressure RHR-PT-37A TDAS PT 155 0-600 143

+/- 1%,

+/- 6 psig

[6/(3x143)] x 100

= 1.47%

RHR-P-2B Discharge Pressure RHR-PT-37B TDAS PT 076 0-600 148.3

+/- 1%,

+/- 6 psig

[6/(3x148.3)] x 100

= 1.35%

RHR-P-2C Discharge Pressure RHR-PT-37C TDAS PT 091 0-600 143.23

+/- 1%,

+/- 6 psig

[6/(3x143.23)] x 100 = 1.40%

HPCS-P-1 Discharge Pressure HPCS-PT-4 TDAS PT 107 0-1500 448.2 (dP)

+/- 1%,

+/- 15 psig

[15/(3x448.2)] x 100 = 1.11%

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GO2-24-003 Page 3 of 3 pump reference value is significantly below the maximum expected operational discharge pressure. A reduction of the range of the PTs to three times the reference value would, in these cases, no longer bound the expected discharge pressure range for these pumps, and therefore is not practicable. If a PT were to fail, a like-for-like replacement would have to be used to ensure suitability for all pump flow conditions. However, this is not a concern because the existing instrumentation provides pump discharge pressure indication of higher accuracy and better resolution than that required by the Code for evaluating pump condition and detecting degradation.

5.4 NUREG-1482, Revision 3 Section 5.5.1 states When the range of a permanently installed analog instrument is greater than three times the reference value, but the accuracy of the instrument is more conservative than that required by the OM Code, the NRC staff may grant relief or authorize an alternative when the combination of the range and accuracy yields a reading that is at least equivalent to that achieved using instruments that meet the OM Code requirements (i.e. up to +/-6 percent for Group A and B tests, and +/-1.5 percent for pressure and differential pressure instruments for Preservice and CPTs).

6. Duration of Proposed Relief Alternative The proposed alternative will be utilized for the entire fifth ten-year IST Program interval, which begins on December 13, 2024, and ends on December 12, 2034.
7. Precedent This relief was previously granted for the CGS fourth ten-year IST Program interval.

Approval of relief was documented in NRC letter to CGS, Columbia Generating Station - Requests for Relief NOs. RG01, RP01, RP02, RP03, RP04, RP05, RP06, RV01, RV02, RV03, and RV04 for the Fourth 10-Year Inservice Testing Interval (TAC NOs. MF3847, MF3848, MF3849, MF3851, MF3852, MF3853, MF3854, MF3855, MF3856, MF3857, and MF3858), dated December 9, 2014 (ADAMS Accession Number ML14337A449).

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GO2-24-003 Page 1 of 2 Relief Request 5IST-03 RP03: Elimination of Two-Minute Hold Time 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 Components Affected

2. Applicable Code Edition and Addenda

ASME OM Code, 2020 Edition, no addenda.

3. Applicable Code Requirements

ISTB-3550, Flow Rate, states, in part, When measuring flow rate, a rate or quantity meter shall be installed in the pump test circuit. If a meter does not indicate the flow rate directly, the record shall include the method used to reduce the data.

ISTB-5300, Positive Displacement Pumps, paragraph (a), Duration of Tests, subparagraphs (1), For the Group A test and the comprehensive test, after pump conditions are as stable as the system permits, each pump shall be run at least two minutes. At the end of this time at least one measurement or determination of each of the quantities required by Table ISTB-3000-1 shall be made and recorded. And (2), For the Group B test, after the pump conditions are stable, at least one measurement or determination of the quantity required by Table ISTB-3000-1 shall be made and recorded.

Relief is required for Group B, and comprehensive and preservice tests.

4. Reason for Request

A rate or quantity meter is not installed in the test circuit. To have one installed would be costly and time consuming with few compensating benefits.

As a result of a rate or quantity meter not being installed in the test circuit, it is impractical to directly measure the flow rate for the Standby Liquid Control pumps.

Therefore, the requirement for allowing a 2-minute hold time for pump tests is an Pump Code Class Pump Group P&ID Dwg. No.

System SLC-P-1A 2

B M522 Standby Liquid Control SLC-P-1B 2

B M522

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GO2-24-003 Page 2 of 2 unnecessary burden which would provide no additional assurance of determining pump operational readiness.

5. Proposed Alternative and Basis for Use

NUREG-1482, Revision 3 Section 5.5.2 states, Requiring licensees to install a flow meter to measure the flow rate and to guarantee the test tank size, such that the pump flow rate will stabilize and then be run for two minutes before recording the data would be a burden because of the design and installation changes to be made to the existing system. Therefore, compliance with the OM Code requirements would be a hardship.

Pump flow rate will be determined by measuring the volume of fluid pumped and dividing by the corresponding pump run time. The volume of fluid pumped will be determined by the difference in fluid level in the test tank at the beginning and end of the pump run (test tank fluid level corresponds to volume of fluid in the tank). The pump flow rate calculation methodology meets the accuracy requirements of OM Code, Table ISTB-3510-1. The pump flow rate calculation is identified on the record of test and ensures that the method for the flow rate calculation yields an acceptable means for the detection and monitoring of potential degradation of the Standby Liquid Control Pumps and therefore, satisfies the intent of OM Code Subsection ISTB.

In this type of testing, the requirement to maintain a 2-minute hold time after stabilization of the system is unnecessary and provides no additional increase of the ability of determining pump condition.

6. Duration of Proposed Relief Alternative The proposed alternative will be utilized for the entire fifth ten-year IST Program interval, which begins on December 13, 2024, and ends on December 12, 2034.
7. Precedent This relief was previously granted for the CGS fourth ten-year IST Program interval.

Approval of relief was documented in NRC letter to CGS, Columbia Generating Station - Requests for Relief NOs. RG01, RP01, RP02, RP03, RP04, RP05, RP06, RV01, RV02, RV03, and RV04 for the Fourth 10-Year Inservice Testing Interval (TAC NOs. MF3847, MF3848, MF3849, MF3851, MF3852, MF3853, MF3854, MF3855, MF3856, MF3857, and MF3858), dated December 9, 2014 (ADAMS Accession Number ML14337A449).

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GO2-24-003 Page 1 of 2 Relief Request 5IST-04 RV01: Alternative Leak Testing Proposed Alternative in Accordance with 10 CFR 50.55a(f)(5)(iii)

Inservice Testing Impracticality

1. ASME Code Components Affected

2. Applicable Code Edition and Addenda

ASME OM Code, 2020 Edition, no addenda.

3. Applicable Code Requirements

ISTC-3630, Leakage Rate for Other Than Containment Isolation Valves, subparagraph (e), Analysis of Leakage Rates, states, in part, that Leakage rate measurements shall be compared with the permissible leakage rates specified by the plant Owner for a specific valve or valve combination.

4. Reason for Request

Impracticality of compliance; these check valves cannot be tested individually and assigning a limiting leakage rate for each valve or valve combination is not practical.

Paragraph ISTC-3630 requires Category A valves, other than containment isolation valves, to be leak tested at least once every two years. Each vacuum relief valve assembly consists of two independent testable check valves in series with no instrument located between them to allow testing of each of the two check valves.

Therefore, leak testing in accordance with the Code is impractical. Modifications to allow individual testing of these valves would require a major system redesign and be burdensome.

Affected Valve Class Cat.

Function System CVB-V-1AB 2

AC To break vacuum on the drywell to suppression chamber downcomers and to limit steam leakage from the downcomer to the wetwell gas space.

Primary Containment Cooling and Purging CVB-V-1CD 2

AC CVB-V-1EF 2

AC CVB-V-1GH 2

AC CVB-V-1JK 2

AC CVB-V-1LM 2

AC CVB-V-1NP 2

AC CVB-V-1QR 2

AC CVB-V-1ST 2

AC

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GO2-24-003 Page 2 of 2

5. Proposed Alternative and Basis for Use

These valves will be leak tested in accordance with CGS TS SR 3.6.1.1.2, SR 3.6.1.1.3, and SR 3.6.1.1.4 during refueling outages.

TS SR 3.6.1.1.2 drywell-to-suppression chamber bypass leakage test monitors the combined leakage of three types of pathways: (1) the drywell floor and downcomers, (2) piping externally connected to both the drywell and suppression chamber air space, and (3) the suppression chamber-to-drywell vacuum breakers. The test frequency is 120 months and 48 months following one test failure and 24 months if two consecutive tests fail until two consecutive tests are less than or equal to the bypass leakage limit.

TS SR 3.6.1.1.3 establishes a leak rate test frequency of 24 months for each suppression chamber-to-drywell vacuum breaker pathway, except when the leakage test of SR 3.6.1.1.2 has been performed (Note to SR 3.6.1.1.3). Thus, each suppression chamber-to-drywell vacuum breaker pathway will have a leak test frequency of 24 months by either SR 3.6.1.1.2 or SR 3.6.1.1.3.

TS SR 3.6.1.1.4 establishes a leakage test frequency of 24 months to determine the suppression chamber-to-drywell vacuum breaker total bypass leakage, except when the bypass leakage test of SR 3.6.1.1.2 has been performed (Note to SR 3.6.1.1.4).

Thus, the determination of suppression chamber-to-drywell vacuum breaker total leakage will have a leak test frequency of 24 months by either SR 3.6.1.1.2 or SR 3.6.1.1.4.

These valves are also verified-closed by position indicators (per TS SR 3.6.1.7.1, ISTC-3700, and I-3370(a)), exercised (per TS SR 3.6.1.7.2, ISTC-3520, and I-3370(a)), and tested in the open direction per TS SR 3.6.1.7.3, ISTC-5221(b), and I-3370(a). In accordance with station procedures, the valves are visually inspected each refueling outage.

6. Duration of Proposed Relief Alternative The proposed alternative will be utilized for the entire fifth ten-year IST Program interval, which begins on December 13, 2024, and ends on December 12, 2034.
7. Precedent This relief was previously granted for the CGS fourth ten-year IST Program interval.

Approval of relief was documented in NRC letter to CGS, Columbia Generating Station - Requests for Relief NOs. RG01, RP01, RP02, RP03, RP04, RP05, RP06, RV01, RV02, RV03, and RV04 for the Fourth 10-Year Inservice Testing Interval (TAC NOs. MF3847, MF3848, MF3849, MF3851, MF3852, MF3853, MF3854, MF3855, MF3856, MF3857, and MF3858), dated December 9, 2014 (ADAMS Accession Number ML14337A449).

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GO2-24-003 Page 1 of 2 Relief Request 5IST-05 RV02: Solenoid Valve Stroke Time Testing Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Components Affected

2. Applicable Code Edition and Addenda

ASME OM Code, 2020 Edition, no addenda.

3. Applicable Code Requirements

ISTC-5150, Solenoid-Operated Valves, paragraph ISTC-5151, Valve Stroke Testing, subparagraph (c) states Stroke time shall be measured to at least the nearest second.

4. Reason for Request

Subparagraph ISTC-5151(c) requires the stroke time of solenoid-operated valves to be measured to at least the nearest second. These nine post-accident sampling solenoid valves are the inboard Containment isolation valves and are operated from a single keylock control switch. It is impractical to measure the individual valve stroke times. To do so would require repetitive cycling of the control switch, or nine Operators and nine stopwatches, which would cause unnecessary wear on the valves and control switches and an excessive burden to Operations personnel with little compensating benefit.

Affected Valve Class Cat.

Function System PSR-V-X73/1 2

A Containment isolation Post-Accident Sampling PSR-V-X80/1 2

A PSR-V-X83/1 2

A PSR-V-X77A/1 1

A PSR-V-X82/1 2

A PSR-V-X84/1 2

A PSR-V-X77A/3 1

A PSR-V-X82/7 2

A PSR-V-X88/1 2

A

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GO2-24-003 Page 2 of 2

5. Proposed Alternative and Basis for Use

All of these solenoid valves stroke in less than two seconds and are considered fast-acting valves. Their safety function is to close to provide containment isolation. The stroke time of the slowest valve will be measured by terminating the stroke time measurement when the last of the nine indicating lights becomes illuminated. If the stroke time of the slowest valve is in the acceptance range (less than or equal to two seconds), then the stroke times of all valves will be considered acceptable.

However, if the stroke time of the slowest valve exceeds the acceptance criteria (two seconds), all nine valves will be declared inoperable and corrective actions in accordance with paragraph ISTC-5153 taken. After corrective actions, the required reference values shall be established in accordance with ISTC-3300. Also, any abnormality or erratic action shall be recorded, and an evaluation shall be made regarding the need for corrective action as required by ISTC-5151(d).

6. Duration of Proposed Relief Alternative The proposed alternative will be utilized for the entire fifth ten-year IST Program interval, which begins on December 13, 2024, and ends on December 12, 2034.
7. Precedent This relief was previously granted for the CGS fourth ten-year IST Program interval.

Approval of relief was documented in NRC letter to CGS, Columbia Generating Station - Requests for Relief NOs. RG01, RP01, RP02, RP03, RP04, RP05, RP06, RV01, RV02, RV03, and RV04 for the Fourth 10-Year Inservice Testing Interval (TAC NOs. MF3847, MF3848, MF3849, MF3851, MF3852, MF3853, MF3854, MF3855, MF3856, MF3857, and MF3858), dated December 9, 2014 (ADAMS Accession Number ML14337A449).

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GO2-24-003 Page 1 of 4 Relief Request 5IST-06 RV03: Main Steam Pressure Relief Valve Testing Sequence Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Components Affected

2. Applicable Code Edition and Addenda

ASME OM Code, 2020 Edition, no addenda.

3. Applicable Code Requirements

Mandatory Appendix I, Paragraph I-3310, Main Steam Pressure Relief Valves with Auxiliary Actuating Devices, states that, Tests before maintenance or set-pressure adjustment, or both, shall be performed for (a), (b), and (c) in sequence. The remaining shall be performed after maintenance or set-pressure adjustments.

(a) visual examination; (b) seat tightness determination, if practicable; (c) set-pressure determination; (d) determination of electrical characteristics and pressure integrity of solenoid valve(s);

(e) determination of pressure integrity and stroke capability of air actuator; (f) determination of operation and electrical characteristics of position indicators; (g) determination of operation and electrical characteristics of bellows alarm switch; (h) determination of actuating pressure of auxiliary actuating device sensing element, where applicable, and electrical continuity; and (i) determination of compliance with the Owner's seat tightness criteria.

Affected Valve Class Cat.

Function System MS-RV-1A,

-1B, -1C, -1D 1

C Overpressure protection Main Steam MS-RV-2A,

-2B, -2C, -2D 1

C MS-RV-3A,

-3B, -3C 1

C MS-RV-3D 1

C Overpressure protection and auto-depressurization of the system to lower reactor pressure sufficient to allow initiation of Low-Pressure Coolant Injection (RHR system utilizing the LPCI mode)

MS-RV-4A,

-4B, -4C, -4D 1

C MS-RV-5B, -5C 1

C

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GO2-24-003 Page 2 of 4

4. Reason for Request

An alternative is proposed to the requirements for the sequence of periodic testing of Class 1 Main Steam pressure relief valves with auxiliary actuating devices as stipulated by Mandatory Appendix I, Paragraph I-3310.

4.1 Remote set-pressure verification devices (SPVD) have been permanently installed on all 18 Main Steam Relief Valves (MSRV) to allow set-pressure testing at low power operation, typically during shutdown for refueling outage and on startup if necessary. These SPVDs incorporate a nitrogen powered, metal bellows assembly that adds a quantified lifting force on the valve stem until the MSRVs popping pressure is reached. Removal and replacement of the MSRVs is normally performed only for valve maintenance and not for the purpose of as-found set-pressure determination. The valves which are required to be as-found set-pressure tested, as part of the OM Code Mandatory Appendix I required periodic testing, do not necessarily correspond to those required to be replaced for maintenance. Actuators and solenoids are separated from the valve and remain in place when MSRVs are removed and replaced for maintenance.

As found visual examinations cannot be performed per the Mandatory Appendix I required sequence while the drywell is inerted. Visual examinations are performed after reactor shutdown but prior to maintenance or set-pressure adjustments.

If due to a reactor scram, MSRV periodic set-pressure testing could not be performed at power during shutdown for a refueling outage, it will be required to be performed during power ascension from the refueling outage or by removing the valves and sending them to the vendor for as-found set-pressure testing.

This would require paragraphs I-3310(a), (d), (e), (f), and (h) tests to be performed during the outage prior to paragraphs I-3310(b), (c) and (i) tests.

Paragraph I-3310(g) is not applicable to these valve designs.

4.2 Valves and "accessories" (actuators, solenoids, etc.) have different maintenance and test cycles due to the methods used for maintenance and testing at CGS as previously discussed in Section 4.1 of this attachment and should be considered separately for the purposes of meeting the required test frequency and testing requirements. Valve testing (i.e., visual examination, seat tightness, set-pressure determination and compliance with Owners seat tightness criteria, in accordance with paragraphs I-3310(a), (b), (c) and (i)) are independent of and can be separate from testing of accessories (i.e., solenoids, actuator, position indicators and pressure sensing element, in accordance with paragraphs I-3310(d), (e), (f), and (h)). Paragraph I-3310 states that tests before maintenance or set-pressure adjustment, or both, shall be performed for I-3310(a), (b), and (c) in sequence. The remaining shall be performed after maintenance or set-pressure adjustments. Valve maintenance or set-pressure

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GO2-24-003 Page 3 of 4 adjustment does not affect accessories testing; likewise, maintenance on accessories does not affect valve set-pressure or seat leakage. Therefore, the MSRVs and the accessories may be tracked separately for the purpose of satisfying the paragraph I-1320 test frequency requirements.

4.3 Paragraph I-3310(f) requires the determination of operation and electrical characteristics of position indicators, and paragraph I-3310(h) requires the determination of actuating pressure of auxiliary actuating device sensing element and electrical continuity. These tests are required to be performed at the same frequency as the valve set-pressure and auxiliary actuating device testing.

The position indicators are all calibrated and functional tested during refueling outages; the sensing elements (pressure switches) are all checked and calibrated at least once per 24 months. Although the existing tests do not have a one-to-one correlation to the valve or actuator tests, these calibrations and functional tests meet all testing requirements of Mandatory Appendix I, and meet or exceed the required test frequency.

5. Proposed Alternative and Basis for Use

5.1 Valves and accessories (actuators, solenoids, etc.) shall be tested separately from MSIV set-pressure and meet paragraph I-1320 test frequency requirements. Since the valve and actuator test and maintenance cycles are different, the plant positions of the actuators selected, or due, for periodic testing may not match the plant positions of the MSRVs selected, or due, for as-found set-pressure testing.

MSRV periodic set-pressure testing will normally be performed at power during shutdown for a refueling outage. As-found visual examination will be performed after set-pressure testing which is out of the specified Mandatory Appendix I required sequence.

If MSRV periodic set-pressure testing could not be performed at power during shutdown for a refueling outage due to a reactor scram it will be required to be performed during power ascension from the refueling outage or by removing the valves and sending them to the vendor for as-found set-pressure testing.

This will require paragraphs I-3310(a), (d) and (e) tests to be performed during the outage prior to paragraphs I-3310(b), (c) and (i) tests.

The actuators and solenoids will be tested at the end of the outage after other maintenance is complete, and the tests will be credited as satisfying the OM Code periodic test requirements provided that no actuator or solenoid maintenance (other than actuator assembly re-installation on a replaced valve) is performed that would affect their as-found status prior to testing or that could affect the valves future set-pressure determination.

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GO2-24-003 Page 4 of 4 5.2 All MSRV position indicators will continue to be tested in accordance with existing surveillance procedures for monthly channel checks, and for channel calibration and channel functional testing, will meet or exceed Code frequency during shutdowns. These tests will be credited for satisfying the requirements of paragraph I-3310(f).

5.3 All auxiliary actuating device sensing elements (pressure switches) will continue to be tested and calibrated on a 24-month frequency. These tests will be credited for satisfying the requirements of paragraph I-3310(h).

6. Duration of Proposed Relief Alternative The proposed alternative will be utilized for the entire fifth ten-year IST Program interval, which begins on December 13, 2024, and ends on December 12, 2034.
7. Precedent This relief was previously granted for the CGS fourth ten-year IST Program interval.

Approval of relief was documented in NRC letter to CGS, Columbia Generating Station - Requests for Relief NOs. RG01, RP01, RP02, RP03, RP04, RP05, RP06, RV01, RV02, RV03, and RV04 for the Fourth 10-Year Inservice Testing Interval (TAC NOs. MF3847, MF3848, MF3849, MF3851, MF3852, MF3853, MF3854, MF3855, MF3856, MF3857, and MF3858), dated December 9, 2014 (ADAMS Accession Number ML14337A449).

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GO2-24-003 Page 1 of 4 Relief Request 5IST-07 RV04: Testing of Reactor Instrument Line Excess Flow Check Valves Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Components Affected Affected Valve Class Cat.

System/Function PI-EFC-X37E, -X37F 1

C System:

Function:

Process Instrumentation for various systems connect to the Reactor Pressure Vessel Excess flow check valves (EFCV) are provided in each instrument process line that is part of the reactor coolant pressure boundary. Design and installation of the EFCVs at CGS conform to RG 1.11.

The reactor instrument line EFCVs close to limit the flow in the respective instrument lines in the event of an instrument line break downstream of the EFCVs outside containment.

PI-EFC-X38A, -X38B,

-X38C, -X38D, -X38E,

-X38F 1

C PI-EFC-X39A, -X39B,

-X39D, -X39E 1

C PI-EFC-X40C, -X40D 1

C PI-EFC-X40E, -X40F 2

C PI-EFC-X41C, -X41D 1

C PI-EFC-X41E, -X41F 2

C PI-EFC-X42A, -X42B 1

C PI-EFC-X44AA, -X44AB,

-X44AC, -X44AD,

-X44AE, -X44AF,

-X44AG, -X44AH,

-X44AJ, -X44AK,

-X44AL, -X44AM 1

C PI-EFC-X44BA, -X44BB,

-X44BC, -X44BD,

-X44BE, -X44BF,

-X44BG, -X44BH,

-X44BJ, -X44BK,

-X44BL, -X44BM 1

C PI-EFC-X61A, -X61B 1

C PI-EFC-X62C, -X62D 1

C PI-EFC-X69A, -X69B,

-X69E 1

C PI-EFC-X70A, -X70B,

-X70C, -X70D, -X70E,

-X70F 1

C PI-EFC-X71A, -X71B,

-X71C, -X71D, -X71E,

-X71F 1

C PI-EFC-X72A 1

C PI-EFC-X73A 1

C

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GO2-24-003 Page 2 of 4 ASME Code Components Affected (continued):

Affected Valve Class Cat.

System/Function PI-EFC-X74A, -X74B,

-X74E, -X74F 1

C System:

Function:

Process Instrumentation for various systems connect to the Reactor Pressure Vessel EFCVs are provided in each instrument process line that is part of the reactor coolant pressure boundary. Design and installation of the EFCVs at CGS conform to RG 1.11.

The reactor instrument line EFCVs close to limit the flow in the respective instrument lines in the event of an instrument line break downstream of the EFCVs outside containment.

PI-EFC-X75A, -X75B,

-X75C, -X75D, -X75E,

-X75F 1

C PI-EFC-X78B, -X78C,

-X78F 1

C PI-EFC-X79A, -X79B 1

C PI-EFC-X106 1

C PI-EFC-X107 1

C PI-EFC-X108 1

C PI-EFC-X109 1

C PI-EFC-X110 1

C PI-EFC-X111 1

C PI-EFC-X112 1

C PI-EFC-X113 1

C PI-EFC-X114 1

C PI-EFC-X115 1

C

2. Applicable Code Edition and Addenda

ASME OM Code, 2020 Edition, no addenda.

3. Applicable Code Requirements

ISTC-3522, Category C Check Valves, subparagraph (c), states, If exercising is not practicable during operation at power and cold shutdowns, it shall be performed during refueling outages.

ISTC-3700, Position Verification Testing, states, in part, that Valves with remote position indicators shall be observed locally at least once every 2 yr to verify that valve operation is accurately indicated.

10 CFR 50.55a(b)(3)(xi), OM condition: Valve Position Indication, states, in part, When implementing paragraph ISTC-3700, "Position Verification Testing," in the ASME OM Code, 2012 Edition through the latest edition of the ASME OM Code incorporated by reference in paragraph (a)(1)(iv) of this section, licensees shall verify that valve operation is accurately indicated by supplementing valve position indicating lights with other indications, such as flow meters or other suitable instrumentation to provide assurance of proper obturator position for valves with remote position indication within the scope of Subsection ISTC including its mandatory appendices and their verification methods and frequencies.

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GO2-24-003 Page 3 of 4

4. Reason for Request

ASME OM Code Subsection ISTC requires testing of active or passive valves that are required to perform a specific function in shutting down a reactor to the safe shutdown condition, in maintaining the safe shutdown condition, or in mitigating the consequences of an accident. The EFCVs are not required to perform a specific function for shutting down or maintaining the reactor in a safe shutdown condition.

Additionally, the reactor instrument lines are assumed to maintain integrity for all accidents except for the Instrument Line Break Accident (ILBA) as described in Final Safety Analysis Report (FSAR), Subsection 15.6.2. The reactor instrument lines at CGS have a flow-restricting orifice upstream of the EFCV to limit reactor coolant leakage in the event of an instrument line rupture. Isolation of the instrument line by the EFCV is not credited for mitigating the ILBA. Thus, a failure of an EFCV is bounded by the CGS safety analysis. These EFCVs close to limit the flow of reactor coolant to the secondary containment in the event of an instrument line break and as such are included in the IST program at the Owner's discretion and are tested in accordance with TS SR 3.6.1.3.8.

5. Proposed Alternative and Basis for Use

Energy Northwest requests an alternative pursuant to 10 CFR 50.55a(z)(1) to test reactor instrument line EFCVs in accordance with TS SR 3.6.1.3.8. This SR requires verification every 24 months that a representative sample of reactor instrument line EFCVs actuate to the isolation position on an actual or simulated instrument line break signal. The representative sample consists of an approximately equal number of EFCVs such that each EFCV is tested at least once every 10 years (nominal). Valve position indication verification of the representative sample will also be performed during valve testing. Any EFCV failure will be evaluated per the CGS Corrective Action Program.

The General Electric (GE) Licensing Topical Report, NEDO-32977-A, Excess Flow Check Valve Testing Relaxation, dated November 1998 (Letter BWROG-00069) and the associated safety evaluation from the NRC (ADAMS Accession Number ML003691722) provides the basis for this relief. The report provides justification for relaxation of the testing frequency as described in TS SR 3.6.1.3.8. The report demonstrates the high degree of EFCV reliability and the low consequences of an EFCV failure. Excess flow check valves have been extremely reliable throughout the industry. There have only been three EFCV failures within the CGS EFCV population since 1985, which results in an estimated failure rate of 8.12E-8 per hour; less than the industry average of 1.01E-7 per hour. Approval of the license amendment request for SR 3.6.1.3.8 was documented in NRC letter to CGS, Columbia Generating Station - Issuance of Amendment Re: Technical Specifications Surveillance Requirement 3.6.1.3.8 (TAC NO. MB0421), dated February 20, 2001 (ADAMS Accession Number ML010590279).

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GO2-24-003 Page 4 of 4 Failure of an EFCV, though not expected as a result of the amended TS change, is bounded by the CGS safety analysis. Based on the GE Topical report and the analysis contained in the FSAR, the proposed alternative to the required exercise frequency and valve indication verification frequency for EFCVs provide an acceptable level of quality and safety. In the safety evaluation for the aforementioned license amendment request, the NRC staff concluded that the increase in risk associated with the relaxation of EFCV testing is sufficiently low and acceptable. Additionally, the staff also concluded that the EFCV Corrective Action Program and performance evaluation criterion are in conformance with the NRC staff-approved guidance, GE Licensing Topical Report NEDO-32977-A, which would ensure a high degree of valve reliability and operability.

6. Duration of Proposed Relief Alternative The proposed alternative will be utilized for the entire fifth ten-year IST Program interval, which begins on December 13, 2024, and ends on December 12, 2034.
7. Precedent This relief was previously granted for the CGS fourth ten-year IST Program interval.

Approval of relief was documented in NRC letter to CGS, Columbia Generating Station - Requests for Relief NOs. RG01, RP01, RP02, RP03, RP04, RP05, RP06, RV01, RV02, RV03, and RV04 for the Fourth 10-Year Inservice Testing Interval (TAC NOs. MF3847, MF3848, MF3849, MF3851, MF3852, MF3853, MF3854, MF3855, MF3856, MF3857, and MF3858), dated December 9, 2014 (ADAMS Accession Number ML14337A449).

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