GO2-14-049, Relief Request for the Columbia Generating Station Fourth Ten-Year Interval Inservice Testing Program

Relief Request for the Columbia Generating Station Fourth Ten-Year Interval Inservice Testing Program

ML14101A365
Person / Time
Site:	Columbia
Issue date:	04/02/2014
From:	Javorik A Energy Northwest
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
GO2-14-049
Download: ML14101A365 (44)

Text

Alex L. Javodk Colm*W Generutng Stadlon I I.. . r P.O. Box 968, PE04 Richia, WA 99352-0968 Ph. 509-377-555

• ~com April 2, 2014 10 CFR 50.55&

G02-14-049 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

COLUMBIA GENERATING STATION, DOCKET NO. 65047 RELIEF REQUESTS FOR THE COLUMBIA GENERATING STATION FOURTH TEN-YEAR INTERVAL INSERVICE TESTING PROGRAM

Dear Sir or Madam,

Pursuant to 10 CFR 50.55a(aX3) and 10 CFR 50.55a(f)(5)(i), Energy Northwest hereby requests NRC approval of the attached relief requests for the upcoming Fourth Ten-Year Interval Pump and Valve Inservice Testing (IST) Program at Columbia Generating Station. As required by 10 CFR 50.55a(f)(4). the Fourth Ten-Year Interval IST Program will comply with the requirements of the American Society of Mechanical Engineers (ASME) Operation and Maintenance (OM) Code (2004 Edition through 2006 Addenda).

Previous IST relief requests for Columbia have been submitted with the overall program plan for the associated ten-year Interval. However, for the upcoming fourth ten-year IST interval, Energy Northwest is submitting the associated relief requests separately and in advance of the overall program plan. The IST overall program plan for the fourth ten-year interval will be submitted by separate correspondence.

Attachment I to this letter provides a comparison between the relief requests for the third ten-year interval and the relief requests for the fourth ten-year interval.

Attachment 2 provides the relief requests for the fourth ten-year interval IST program.

The Fourth Ten-Year Interval Program will be in effect from December 13, 2014 to December 12, 2024. Energy Northwest requests approval of the relief requests by November 1, 2014, to allow time for implementation before the start of the Interval.

There are no new or revised regulatory commitments contained in this submittal. If you have any questions or require additional information, please contact Ms. L. L. Williams at (509) 377-8148.

RELIEF REQUESTS FOR THE COLUMBIA GENERATING STATION FOURTH TEN-YEAR INTERVAL INSERVICE TESTING PROGRAM Page 2 of 2 Executed this day of -0___2014.

Respecftully, A. L. Javork Vice President, Engineering Attachments: 1. Comparison Between Relief Requests for the Third Ten-Year Interval and Relief Requests for the Fourth Ten-Year Interval

2. Relief Requests for the Columbia Generating Station Fourth Ten-Year Interval Inservice Testing Program cc: NRC Region IVAdministrator NRC NRR Project Manager NRC Senior Resident Inspector/988C M.A. Jones - BPAM 399

REUEF REQUESTS FOR THE COLUMBIA GENERATING STATION FOURTH TEN-YEAR INTERVAL INSERVICE TESTING PROGRAM Comparison Between Relief Requests for the Third Tan-Yeor Interval and Relief Requests for the Fourth Ten-Year Interval A comparison between the relief requests for the third ten-year interval and the relief requests for the fourth ten-year interval is shown in the following table.

Relief Request Number Equivalent or New Relief Comments In 3r Ten Year Interval Request Number In 4" Ten Plan Year Interval Plan RG01 New Relief Request to use Code Case OMN-20 for

............. ... .. . _Frequency Grace RP01 RP01 RP03 RP02 RP04 RP03 RP05 RP04 RP06 RPO5 RP07 Deleted - ISTB-3510(bX2) revised to incorporate Code Case OMN-6 in OMb 2006

___addenda RP06 New Relief Request to use Code Case OMN-19 Alternate Upper Limit for the Comprehensive Pump Test RV01 RV01 RV02 Deleted - ISTC-5100 revised to incorporate Code Case OMN-8 in OMb 2006 addenda.

RV03 RV02 RV04 RV03 RV05 RV04 Details are provided in the individual relief requests provided In Attachment 2 to this letter.

REUEF REQUESTS FOR THE COLUMBIA GENERATING STATION FOURTH TEN.

YEAR INTERVAL INSERVICE TESTING PROGRAM Relief Requests for the Columbia Generating Station Fourth Ten-Year Interval Inservice Testing Program

4ST Proam Plan Columbia Generating Station P I of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RGOI Proposed Altwnative In Accordanr with 10 CFR 5.5*e(aX3XI)

- Hardship or Unusual Difficulty Without Compensating increase in Level of Quality and Safety -

AlN Pumps and Valves contained within the Inservice Testing Program scope.

Am -- Code Editnd ab-- Addenda The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code.

AalSM Code Rau*

This request applies to the frequency specifications of the ASME OM Code. The frequencies for tests given in the ASME OM Code do not include a tolerance band.

ISTA-3120(a) Inservice Testinm Interval. The frequency for the inservice testing shall be in accordance with the requirements of Section IST.

ISTB-3400 F~guec of knev Tet. An inservice test shall be run on each pump as specified in Table ISTB-3400-1.

ISTC-3510 Exercisig Test Freguencv. Active Category A, Category B, and Category C check valves shall be exercised nominally every 3 months, except as provided by ISTC-3520, ISTC-3540, ISTC-3550, ISTC-3570, ISTC.5221, and ISTC-5222. Power-operated relief valves shall be exercise tested once per fuel cycle.

ISTC-3540 Maual . Manual valves shall be full-stroke exercised at least once every 2 years, except where adverse conditions may require the valve to be tested more frequently to ensure operational readiness. Any increased testing frequency shall be specified by the Owner. The valve shall exhibit the required change of obturator position.

ISTC-3630 (a) Leakage Rate for Other Than Contaiment isolatio Valves.

Fegunc. Tests shall be conducted at least once every 2 years.

ISTC-3700 Position Veification Testin. Valves with remote position indicators shall be observed locally at least once every 2 years to verify that valve operation is accurately Indicated.

iST Program Plan Columbia Generating Station Page 2of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RG0I (Contd.)

ISTC-5221(c)(3) VAMe bWo hMovrnen. At least one valve from each group shall be disassembled and examined at each refueling outage; all valves In a group shall be disassembled and examined at least once every 8 years.

ISTC-5260 Explosvely Actuated Valves. (b) Concurrent with the first test and at least once every 2 years, the service life records of each valve shall be reviewed to verify that the service life of the charges have not been exceeded and will not be exceeded before the next refuel. (c) At least 20% of the charges I explosively actuated valves shall be fired and replaced at least once every 2 years.

Appendix 1,1-1320(a) Test Freauencies. Class I Pressure Relief Valvs, UY r Test Jinr.* Class I pressure relief valves shall be tested at least once every 5 years, starting with initial electric power generation.

No maximum limit Is specified for the number of valves to be tested within each interval; however, a minimum of 20% of the valves from each valve group shall be tested within any 24 month Interval.

Appendix I, 1-1330 Test Freouencv. Class I Nonre1osino Pressure Relief Devices.

Class 1 nonrecloslng pressure relief devices shaft be replaced every 5 years unless historical data indicates a requirement for more frequent replacement.

Appendix I, 1-1340 I*nLFgauncnyx, Class I Pressure Relief Valves that are used for Thermal Relief Application. Tests shall be performed in accordance with 1-1320, Test Frequencies, Class 1 Pressure Relief Valves.

Appendix 1,1-1350(a) Test Freouencv. Class 2 and 3 Pressure Relief Valves. 10-Year 1t2t Interval, Classes 2 and 3 pressure relief valves, with the exception of PWR main steam safety valves, shall be tested every 10 years, starting with initial electric power generation. No maximum limit is specified for the number of valves to be tested during any single plant operating cycle; however, a minimum of 20% of the valves from each valve group shall be tested within any 48 month interval.

Appendix I, 1-1360 Test FreOuency. Class 2 and 3 Nonreclosing Pressure Relief Qojas. Classes 2 and 3 nonreclosing pressure relief devices shaft be replaced every 5 years, unless historical data indicates a requirement for more frequent replacement.

1ST lO-w, te Columbia Generating Station P 4th .-

1 Year Interval (Relief Requests Only)

Relief Request - RGOI (Contd.)

Appendix 1,1-1370 Test Freauencv. Class 2 and 3 Primary QConne Vacuum

• flo...YAM. (a) Tests shell be performed on all Classes 2 and 3 containment vacuum relief valves at each refueling outage or every 2 years, whichever is sooner, unless historical data requires more frequent testing. (b) Leak tests shall be performed on all Classes 2 and 3 containment vacuum relief valves at a frequency designated by the Owner in accordance with Table ISTC-3500-1.

Appendix i, 1-1380 Test Freouencv. Classes 2 and 3 Vacuum Relief Valves. Exceot fo Primary Containment Vacuum Relief Valves. AlI Classes 2 and 3 vacuum relief valves shall be tested every 2 yr, unless performance data suggest the need for a more appropriate test interval.

Appendix 1,1-1390 Test Freauencv. Classes 2 and 3 Pressure Relief Devices That Are Used for Thermal Relief AWotication. Tests shall be performed on all Classes 2 and 3 relief devices used in thermal relief application every 10 yr, unless performance data indicate more frequent testing is necessary. In lieu of tests the Owner may replace the relief devices at a frequency of every 10 yr, unless perfomrmnce data indicate more frequent replacements are necessary.

Appendix 11,11-4000 Performance Imoovemnent Activities. (aX1) If sufficient information Is not currently available to complete the analysis required in 11-3000, or if this analysis is Inconclusive, then the following activities shall be performed at sufficient intervals over an interim period of the next 5 years or two refueling outages, whichever Is less, to determine the cause of the failure or the maintenance patterns. (e) Identify the interval of each activity.

Appendix 11,114000 Omization of Cordlio Mon na Activite. (bX1 Xe) Identify the Interval of each activity. Interval extensions shall be limited to one fuel cycle per extension. Intervals shall not exceed the maximum intervals shown In table 11-4000-1. All valves in a group sampling plan must be tested or examined again, before the interval can be extended again, or until the maximum interval would be exceeded. The requirements of ISTA-3120, Inservice Test Interval, do not apply.

MOV Diagnostic Tests GL 96-05 reguired 2erodic static and dynamic diaanostic test intrvals The MOV Program is required by condition 10 CFR 50.55a(bX3)(ii).

1ST Program Plan Columbia Generating Station 4of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RG01 (Contd.)

Reason forRaue Pursuant to 10 CFR 50.55a, 'Codes and standards," paragraph (aX3Xil), relief is requested from the frequency specifications of the ASME OM Code. The basis of the relief request is that the Code requirement presents an undue hardship without a compensating increase in the level of quality of safety.

ASME OM Code Section IST establishes the IST frequency for all components within the scope of the Code. The frequencies (e.g., quarterly) have always been Interpreted as "nominar frequencies (generally as defined in the Table 3.2 of NUREG-1482, Revision 2) and Owners routinely applied the surveillance extension time period (i.e., grace period) contained in the plant Technical Specifications (TS) SurveilMance Requirements (SRs). The TSs typically allow for a less than or equal to 25% extension of the surveillance test interval to accommodate plant conditions that may not be suitable for conducting the surveillance (SR 3.0.2).

However, regulatory issues have been raised concerning the applicability of the Technical Specification (TS) "grace perod" to ASME OM Code required IST frequencies irrespective of allowances provided under TS Administrative Controls (i.e., TS 5.5.6, "Inservice Testing Program," invokes Surveillance Requirement (SR) 3.0.2 for various OM Code frequencies).

The lack of a tolerance band on the ASME OM Code IST frequency resticts operational flexibility. There may be a conflict where IST could be required (i.e., its frequency could expire), but where it is not possible or not desired that it be performed until after a plant condition or associated Limiting Condition for Operation (LCO) is within its applicability.

Therefore, to avoid this conflict, the IST should be performed when It can and should be performed.

The NRC recognized this potential issue in the TS by allowing a frequency tolerance as described in TS SR 3.0.2. The lack of a similar tolerance applied to the ASME OM Code testing places an unusual hardship on the plant to adequately schedule work tasks without operational flexibility.

Thus, just as with TS required surveillance testing, some tolerance is needed to allow adjusting ASME OM Code testing intervals to suit the plant conditions and other maintenance and testing activities. This assures operational flexibility when scheduling IST that minimizes the conflicts between the need to complete the testing and plant conditions.

Progg" fA ft4mtand Bull fr Use Columbia Generating Station proposes to use the ASME OM Code Case OMN-20 as published in ASME OM-2012 edition for the fourth ten year interval of IST Program. The 2012 edition of Operation and Maintenance of Nuclear Power Plants, was approved by the ASME Board on Nuclear Codes and Standards on December 21, 2012. Code case OMN-20 will be used for determining acceptable tolerances for pump and valve testing frequencies. The code case as published in ASME OM-2012 edition is repeated below.

IST Progron Plan Columbia Generating Station 5of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RGOI (Contd.)

publshWed OMN.20 Cod. Case I TEST FREQUENCY GRACE ASME OM, Division 1, Section IST and al earlier editions and addenda specify component test frequencies based either on elapsed time periods (e.g., quarterly, 2 years, etc.) or the occurrence of plant conditions or events (e.g., cold shutdown, refueling outage, upon detection of a sample failure, following maintenance, etc.).

a) Components whose test frequencies are based on elapsed time periods shall be tested at the frequencies specified In Section IST with a specified time period between tests as shown in Table 1. The specified time period between tests may be reduced or extended as follows:

1) For periods specified as fewer than 2 yr, the period may be extended by up to 25% for any given test.

2) For periods specified as greater than or equal to 2 yr, the period may be extended by up to 6 mo for any given test.

3) All periods specified may be reduced at the discretion of the owner (i.e., there is no minimum period requirement).

Period extension is to facilitate test scheduling and considers plant operating conditions that may not be suitable for performance of the required testing (e.g., performance of the test would cause an unacceptable increase in the plant risk profile due to transient conditions or other ongoing surveillance, test, or maintenance activities). Period extensions are not intended to be used repeatedly merely as an operational convenience to extend test intervals beyond those specified.

Period extensions may also be applied to accelerated test frequencies (e.g., pumps in alert range) and other less than 2 yr test frequencies not specified in Table 1.

Period extensions may not be applied to the test frequency requirements specified in Subsection ISTD, Preservice and Inservice Examination and Testing of Dynamic Restraints (Snubbers) in Light-water Reactor Nuclear Power Plants, as Subsection ISTD contains its own rules for period extensions.

(b) Components whose test frequencies are based on the occurrence of plant conditions or events may not have their period between tests extended excepts as allowed by ASME OM, Division 1, Section IST, 2009 Edition through OMa-2011 Addenda and all earlier editions and addenda.

IST Program Plan Columbia Generating Station P o 4th 10-Year Interval (Relief Requests Only)

Relief Request - RGO1 (Contd.)

Table i Specified Test Frequencies Frequeny peci8 fte Time Period Between Tests

.(or, 92 days Lrevery 3mot) ______________ ___

Semiannually 184 days (or every 6 months) ... d. ..

Annually (or every year) 368 days X Years X calendar years rWhere X is a whole number of years> 2 Qualkty/s*ffiltvIm Allowing use of the code case OMN-20 will provide reasonable assurance of operational readiness of pumps and valves subject to ASME OM code 2004 edition through OMb-2006 addenda testing requirements.

Duration of Prooose AlVrMM#M Fourth 10 year interval.

Emadlm The following similar relief requests for Quad Cities Unit 1 and 2, and Three Mile Island Unit I were approved by the NRC.

Request Number RV-01 for Quad Cities Units 1 and 2 was approved by the NRC by letter dated February 14,2013 (ADAMS Accession Number ML13042A348).

Request Number VR-02 for Three Mile Island Unit 1 was approved by the NRC by letter dated August 15, 2013 (ADAMS Accession number ML13227A024).

1. Code Case OMN-20, Inservice Test Frequency, published in ASME OM-2012 Edition.

,ST Program Plan Columbia Generating Station Po 7of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RPOI in Accordance with 10 CFR 50.55a(aX3XI)

- Alternative Provides Acceptable Level of Quality and Safety -

AW rd Lgabst fto Pump " Class Code Gu Pump P & IDDwg. No. System(s)

SW-P-1A 3 A M524, SH I Standby Service Water SW-P-lB 3 A M524, SH 2 Standby Service Water HPCS-P-2 . 3 A M524, SH 1 Standby Service Water, HIP Apoftabb Code Edition and Adkkads The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code.

AAmlicable Codle Reauir-.entM Measure pump differential pressure, AI. Vertical line shaft centrifugal pumps preservice and inservice testing (ISTB-5210, ISTB-5220, and Table ISTB-3000-1). Relief is required for Group A and comprehensive and preservice tests.

lftsonfor lnuest 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 determirnng differential pressure for the pump.

Proposed Alterntive ajnd Basis fbr U" 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 the Code Table ISTB-5221 -1. 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.

1. SW-P-1A, I B, and HPCS-P-2 are vertical line shaft centrifugal pumps which are immersed in their water source. They have no suction line which can be instrumented.

2. Technical Specification SR 3.7.1.1 specifies the minimum allowable spray pond level to assure adequate NPSH and ultimate heat sink capability.

4ST 10-Yerr Plnt Columbia Generating Station P 8 of 40 4.th 10-Year Interval (Relief Requests Only)

Relief Request - RPOI (Contd.)

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 Test Program and suction pressure will be considered constant. Administratively, the pond level is controlled within a nine (9) inch band.

4. Acceptable flow rate and discharge pressure will suffice as proof of adequate suction pressure.

5. These pumps operate with a suction lift. 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. Thus 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:

AP = Pd - F PJ)

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

CASE 1 CASE 2 Suton Head Suction Lift

+Wd T Dbcharge Suco Pis PdHa Hedon m

ISTAPOIdrSa*Qfile

IST Prorm Plan Columbia Gener ing Station Pap 9of40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RI (Contd.)

The ASME Code uses the term 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 Heed But in Case 2 (Service Water Pumps)

Total Head a Discharge Head + Suction Lift When one converts head to pressure, the equivalent formula for diffrential pressure would be:

AP(psi) = Pd(psi)+ 0.431(psiift) x (ELv(ft)- EL ~v,=(ft))

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.

The effect of setting the Code Acceptance Criteria on discharge pressure instead of differential pressure as specified in the Code provides a more conservative test methodology.

DMurato MI PEr92o2d AlenUlMM Fourth 10 year interval.

This relief was granted for the third 10 year Interval. NRC approval was documented in a letter dated May 15, 2007 (ADAMS Accession Number ML071010344, TAC No. MD3536) for Relief Request No.

RPOI.

ST Pro-ra Plan Columbia Generating Station P 10 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RP02 Relief RuMet In Accordance with 10 CPR 5O.5e(f)(5XIii)

- Inservice Testing Impracticality -

hemd PUMPPumpClass ode Pump Growp P&Io owg. Number System(s)

SW-P-IA 3 A M524, SH 1 Standby Service Water SW-P-lB 3 A M524, SH 2 Standby Service wat HPCS-P-2 3 A M524, SH 1 Standby Service Water, HPCS Mik"Coe EM M dag The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code.

L~QULBU~r32U~

Subsection ISTB-5221(b) and ISTB-5223(b). The resistance of the system shall be varied until the flow rate equals the reference point. The differential pressure shall then be determined and compared to the reference value. Alternatively, the flow rate shall be varied until the differential pressure equals the reference point and the flow rate determined and compared to the reference flow rate value.

Relief is required for Group A and comprehensive tests.

The establishment of specific reference values is impractical for these vertical line shaft centrifugal pumps.

Burde Caused by Compliance

1. Service Water systems are designed such that the total pump flow cannot be adjusted to one finite value for the purpose of testing without adversely affecting the system flow balance and Technical Specification operability requirements. Thus, these pumps must be tested in a manner that the Service Water loop remains properly flow balanced during and after the testing and each supplied load remains fully operable to maintain the required level of plant safety.

1ST Prga Pla Columbia Generating Station Page 11 of 40 4th 10O-Year Interval (Relief Request. Onl)

Relief Request - RP02 (Contd.)

2. The Service Water system loops are not designed with a fUl flow test line with a single throttle valve. Thus the flow cannot be throttled to a fixed reference value. Total pump flow rate can only be measured using the total system flow indication installed on the common return header. Although there are valves in the common return line that are used for throttling total system flow during pre-service testing, use of these valves is impractical for regular test due to the potential effect on the flow balance for the safety related loads. Each main loop of service water supplies 17-18 safety related loads, all piped in parallel with each other. The HPCS-P-2 pump loop supplies four loads, each in parallel. Each pump is independent from the others (i.e., no loads are common between the pumps). Each load is throttled to a calculation and surveillance required flow range which must be satisfied for the loads to be operable. All loads are aligned in parallel, and all receive service water flow when the associated service water pump is running, regardless of whether the served component itself is in service. During power operation, alt loops (subsystems) of service water are required to be operable per Technical Specifications. A loop of service water cannot be taken out of service for testing without entering an Action Statement for a Limiting Condition for Operation (LCO) per Technical Specification 3.7.1.

3. Each loop of Service Water is flow balanced annually to ensure that all loads are adequately supplied. A flow range Is specified for each loed. Once property flow balanced, very little flow adjustment can be made for any one particular load without adversely impacft the operability of the remaining loads (increasing flow for one load reduces flow for all the others). Each time the system is flow balanced, proper individual component flows are produced, but this in turn does not necessarily result in one specific value for total flow. Because each load has an acceptable flow range, overall system full flow (the sum of the individual loads) also has a range. Total system flow can conceivably be in the ranges of approximately 9,200 -

10,200 gallons per minute (gpm) for SW-P-1A and SW-P-lB pumps and approximately 961 -

1,203 gpm for HPCS-P-2 pump. Consequently, the requirement to quarterly adjust service water loop flow to one specific flow value for the performance of inservice testing conflicts with system design and component operability requirements (i.e., flow balance) as required by Technical Specification.

PPEd2MAteratve and §l1i for Use As discussed above, it is impractical to return to a specific value of flow rate or discharge pressure for testing of these pumps. As stated in NUREG-1482, Rev 2 Section 5.2, some system designs do not allow for testing at a single reference point or a set of reference points. In such cases, it may be necessary to plot pump curves to use as the basis for variable reference points. Code Case OMN-16,"Use of a Pump Curves for Testing,* is included in draft Revision I of Regulatory Guide (RG) 1.192,"Operations and Maintenance Code Case Acceptability, ASME OM Code.* Flow rate and discharge pressure are measured during inservice testing and compared to an established reference curve. Discharge pressure instead of differential pressure is used to determine pump operational readiness as described in Relief Request RP01. The following elements ae used in developing and implementing the reference pump curves. These elements follow the guidance of Code Case OMN-16.

IST Pr@W=m Plan Columbia Generating Station P of 40 4th 10-Year I (Relief Requests Only)

Relief Request - RP02 (Contd.)

1. SW-P-1A and SW-P-1B were replaced with new pumps in 2005 and HPCS-P-2 was replaced in 2008. A preservice test as required by the ASME OM Code was performed and a reference pump curve (flow rate vs. discharge pressure) was established for all three pumps using the preservice test data.

2. Pump curves are based on five or more test points beyond the flat porlton of the curve (between 6000 gpm and 10200 gpm for SW-P-1A and 18 pumps and between 650 and 1200 gpm for HPCS-P-2 pump). The pumps are being tested near full design flow rate.

3. Temporary test gauges (1 0.5% full scale accuracy) were installed to take discharge pressure test data in addition to plant installed gauges, and Transient Data Acquisition System (TDAS).

TDAS data averages 100 readings with a reading taken each second. All Instruments used either met or exceeded the Code required accuracy for Group A and comprehensive pump test.

4. The reference pump curves are based on flow rate vs. discharge pressure. Acceptance criteria curves are based on differential pressure limits given In Table ISTB-5121-1 for applicable test type. Setting the Code Acceptance Criteria on discharge pressure using differential limits is slightly more conservative for these pump installations with suction lift (Relief Request RP01). See the attached sample SW-P-1A pump Acceptance Criteria sheet for Group A test. Area 1-2-5-6 is the acceptable range for pump performance. Area 3-4-5-6 defines the Alert Range, and the area outside 1-2-3-4 defines the required Action Range.

5. Similar reference curves are used for comrnehenslve pump tests using the applicable acceptance criteria and instrument accuracy and range requirements.

6. Only a small portion of the established reference curve is being used to bind the flow rate variance due to flow balancing of various system loads. See the attached sample SW-P-1A pump Acceptance Criteria sheet for Group A test.

7. A single reference value shall be assigned for each vibration measurement location. The selected reference value shall be at the minimum data over the narrow range of pump curves being used as required by Code Case OMN-16.

8. When the repair, replacement, or routine servicing of a pump may have affected a reference curve, a new reference curve shall be determined, or the existing reference curve reconfirmed, in accordance with pare. 16-3310 of Code Case OMN-16.

9. If It is necessary or desirable, for some reason other than that stated In para. 16-3310 of Code Case OMN-16, to extend the current pump curve or establish an additional reference curve, the new curve(s) must be determined in accordance with para. 16-3320 of Code Case OMN-16.

iST Program Plan Columbia Genertng Station Page 13 of°40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RP02 (Contd.)

Qualbtlafed Imw The desin of the Gq ba Gener hatiorSevioe Water syMem and the-Tehia Specifcation requirements e i impractical to a:just system flow to a fixed, referenoe value for inservice testing without ad "Vsel WVlnthe system flow balan*o and Technical Specification operability requiremen(s The propioN altemate testing using a referenoe pump curve for each pump provides adequate qsurance and accura"Qn mront pump coration to, assessi pump operational readiness dntl shall, adequately detedt- 0 degradation. Altbmate ktstn will have nO adverse impact on plant and public safety.

Duraton of MgIS Atlftm te -*.

1~,

Fourth 10 year interval. i Similar rneie as granted for the third 10 year interval. NRC )pproval was docmoented in a letter dated May l&l*p (ADAMS AcceSsion Nuber ML071019343, TAC No. 4!D3540) for Relief Request No, 0P03. *.

I

'4 i

4-'.

4ST P0.=, fnt Columbia Generating Station P 14 of 40 4th 10-Year I (Relief Requests Only)

Relief Request - R@ (Contd.)

SAMPLE SW-P-1ADATA SHEET - GrouD ACCEPTANCE A Test CRITERIA 240 SW4 JA ACCEPTANCE Q ITERIA 235 230 225 220 LIU 215 210 I 205 2O0 t95 190 185 180 4" 9.330 9A30 9,530 9,630 9,730 9.830 9.930 10,030 10,130 10,230 FLOW - GPM ALERT RANGE st Area Inside 3-4-54 ACTION RANGE a Area Outside 1-2-3-4

4ST Program Plan Columbia Generating Station Pag. 15 of 40 4th 10-Year Interval(RleRq (Relief Request* etOny Only)

Relief Request - RPo3 InAcodnceR"le elwith 10 FRu R*sT" 5Use.Saf(X.I)

- inservice Tesng impracticality -

A6WI Code Compbrwnta ,&Mbtl Pump Code Class Pump Group MSysem(s)

___ ___ ___ ___ Number ____ ___ ____ ___

LPCS-P-1 2 B M52 Low Pressure Core Spray RHR-P-2A 2 A M521, SH I RHR-P-2B 2 A M521, SH 2 Residual Heat Removal RHR-P-2C 2 A M521, SH 3 HPCS-P-1 2 B M520 High Pressure Core Spray RCIC-P-1 2 B M519 Reactor Core Isolation Colng F= ZIP" 7716ý17 71 -wrlIlk'.7-IT"71", UT-77771 The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code.

A1mimb C2111 RCIC-P-1 (Centrfuos B=o~

Grou B Tet: Subsection ISTB-5122(a). ISTB-5122(b) and ISTB-5122(c). The pump shall be operated at a speed adjusted to the reference point (11%) for variable speed drives. The differential pressure or flow rate shall be determined and compared to its reference value. System resistance may be varied as necessary to achieve the reference point Com-rsir Test: Subsecton ISTB-123(a) and ISTB-5123Mb). The pump shall be operated at a speed adjusted to the reference point (t1 %) for variable speed drives. The resistance of the system shall be varied until the flow rate equals the reference point. The differential pressure shall then be determined and compared to its reference value. Altematively, the flow rate shall be varied until the differential pressure equals the reference point and the flow rate determined and compared to the reference flow rate value.

Other Pures (Vertl line Shaft Cenfugal Pures):

Grou2 B Test for LPCS.P-1 and HPCS-P-1: Subsection ISTB-5222(b) and ISTB-6222(c). The differential pressure or flow rate shall be determined and compared to Its reference value. System resistance may be varied as necessary to achieve the reference point.

Groug A Test for RHR-P 2A. 26 AND 2C and Comorehensive Test for all g=ons exceot RCIC-P-1:

Subsection ISTB-5221b and ISTB-5223(b). The resistance of the system shall be varied until the flow rate equals the reference point. The differential pressure shall then be determined and compared to its reference value. Alternatively, the flow rate shall be varied until the differential pressure equals the reference point and the flow rate determined and compared to the reference flow rate value.

1ST Program Pftn Columbia Generating Station Pop 16 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RPO3 (Contd.)

The establishment of specific reference values Is impractical for these pumps.

Burden Causd by rdRU Reference values are defined as one or more fixed sets of values of quantities as measured or observed when the equipment is known to be operating acceptably. All subsequent test results are to be compared to these reference values. Based on operating experience, flow rate (Independent variable during Inservice testing) for these pumps cannot be readily duplicated with the existing flow control systems. Flow control for these systems can only be accomplished through the operation of relatively large motor operated globe valves as throttling valves. Because these valves are not equipped with position indicators which reflect percent open, the operator must repeatedly jog the motor operator to try to make even minor adjustments in flow rate. These efforts, to exactly duplicate the reference value, would require excessive valve manipulation which could ultimately result In damage to valves or motor operators.

B=2Wse Alternativnd BAMsI"& for Use As discussed above, it is impractical to return to a specific value of flow rate, or differential pressure for testing of these pumps. As stated in NUREG-1482, Rev 2 Section 5.2, some system designs do not allow for testing at a single reference point or a set of reference points. In such cases, it may be necessary to plot pump curves to use as the basis for variable reference points. Code Case OMN-16,"Use of a Pump Curves for Testing," is included in draft Revision 1 of RG 1.192,"Opeeations and Maintenance Code Case Acceptability, ASME OM Code."

Since the independent reference variable (flow rate) for these pumps Is impractical to adjust to a fixed reference value and requires excessive valve manipulation, the maximum variance shall be limited to t2%of the reference value. Thus, flow rate shall be adjusted to be within + 2% of the reference flow rate and the corresponding differential pressure shall be measured and compared to the reference differential pressure value determined from the pump reference curve established for this narrow range of flow rate. Slope of the pump reference curve Is not flat even over this narrow range of flow rate. Assuming the flow rate to be fixed over this narrow range can result in additional error in calculating the deviation between the measured and reference differential pressure and at times this deviation can be non-conservative. Since the dependent variable (differential pressure) can be assumed to vary linearly with flow rate in this narrow range, establishing multiple reference points in this narrow range is similar to establishing a reference pump curve representing multiple reference points. This assumption of linearity between differential pressure and flow rate is supported by the manufacturer pump curves in the stable design flow rate region.

h 10-Yearn PI n Columbia Generating Station Page 17of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RP03 (Contd.)

The following elements are used in developing and Implementing the reference pump curves. These elements follow the guidance of Code Case OMN-16.

1. RHR-P-2B was replaced with a new pump in 2013. A preservice test as required by the ASME OM Code was performed and a reference pump curve (flow rate vs. differential pressure) was established for this pump using the preservice test data. A similar reference pump curve (flow rate vs differential pressure) has been established for RHR-P-2A and RHR-P-2C pumps from data taken on these pumps when they were known to be operating acceptably. These pump curves represent pump performance almost identical to manufacturers test data.

2. For RCIC-P-1, a variable speed drive pump, flow rate is set within +/-2% of the reference flow rate and the reference curve is based on speed with acceptance criteria based on differentel pressure. This Is done because of the imnprcticaty of sotlng speed to a specific reference value to achieve the desired flow rate and pump discharge pressure. See the attached sample RCIC-P-1 pump Acceptance Criteria sheet for Group Btest. Additionally, evaluation of the manufacturer pump data, preoperational and special test data used to establish the pump reference curve indicates Insignificant change in differential pressure with small variation in flow rate.

3. HPCS-P-1 was replaced with a new pump in 2007. A preservice test as required by the ASME OM Code was performed and a reference pump curve (flow rate vs. differential pressure) was established for this pump using the preservice test data.

4. For LPCS-P-1 pump, the reference pump curve is based on the manufacturer pump curve that was validated during preoperational testing using 5 or more test points beyond the flat portion of the curve.

5. Residual Heat Removal (RHR), High Pressure Core Spray (HPCS) and Reactor Core Isolation Cooling (RCIC) pump curves are based on five or more test points beyond the flat portion of the curve. These ECCS pumps have minimum flow rate requirements specified in Technical Specifications and are being tested near these flow rates.

6. Temporary test gauges (:t 0.5% full scale accuracy) were installed to take suction and discharge pressure test data in addition to plant installed gauges and Transient Data Acquisition System (TDAS). TDAS date averages 100 readings with a reading taken each second. All instruments used either met or exceeded the Code required accuracy for applicable Group A, Group B and comprehensive pump test.

7. Review of the pump hydraulic data trend plots Indicates close correlation with the established pump reference curves, thus further validating the accuracy and adequacy of the pump curves to assess pumps operational readiness.

8. Acceptance criteria curves are based on differential pressure limits given in applicable Table ISTB-5121-1 or Table ISTB-5221-1. See the attached sample RHR-P-2A pump Acceptance Criteria sheet for Group A test. Area 1-2-5-6 is the acceptable range for pump performance.

Area 3-4-5-6 defines the Aled Range and the area outside 1-2-3-4 defines the required Action

IST Program Plan Columbia Generating Station Pa 18 of 40O 4th 10-Year Interval (Relief Requests Only)

Relief Request - RP03 (Contd.)

Range. A similar sample RCIC-P-1 pump Acceptance Criteria sheet for Group 8 test is also attached.

9. Similar reference curves will be used for m rhen.ve p ui n

10. Only-44 Sn* pk~toq of the established wreferewie 4urve is bi"n tsed to accommodate flow rate wgria+ce. ea sample pump c ptce Criteria u shetp.

11. Asr eeeievalueý, be Ossigned fbr e8ch votwaon measurement Ioctln. Th rife, value SAWIW+t rnim dgta o4e the naw angd of pomp owves being se as required by Code e1

12. Wheaý jhe repa.re~acement, 'or rmitine'seryVIn of a pumrp' mayi havO affected a reference curv4, is nw referenpe cMrv sWaW be d=etprmird, C*4h xistin reference curve reconflrrned, in accqrdace witp .16-330 of Code CsO is,

13. Ifit 1* or dcir", carYfor sofie reason othe than that staitac n para. 16-3310 o Code Case

ýt extendý the current pu*N curve or estWblsh an addlUDws reference curve, the CW ¶n~t be, determined InOccoidlanco with para. 1643320 of Code Case OMN-16.

Due to impQ adjusting indeoendqt vu hailA rates, and speedfo ailkrveRI pump) to a irferefor alue rvr tet ihe.system modifications, alt~ernate testing to vary thee vae~~e ovor a 40ry,.narroW range (tup to +/- %% eetec values) ind using pump reference ciwves rUs,. narrow is1proposed. Alternate testineis-ng arePerence PUm Pcurve for each puiip pbvid pote ..a

~ a. o*Ufoe ard accursqy In monIt*H + condition to assess pump operational readiness and wip adequef4~tect pump degaain htife elq~ttesting

1. will have no adverse impact on plant and publt Fourth 10 year interval.'

Pemgogden Similar relief was granted for the third 10 year W:ter1. NRC approval was docufiVlPte4 In letter dated March 23, 2007 (ADAMS Accession Nurn:e$MLOTO600I 11, TAO No. MVDb6353740rellef Request No. RPO4.

4ST Progrval Columbia Generating Station P 19 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RP03 (Contd.)

SAMPLE DATA SHEET. GroQ A Test RHR-P-2A ACCEPTANCE CRITERIA 131 130 129 128 127 126 125 124 123 122 121

£ 120 119 118 117 . ...... - - - - - - - - - -- - - - - - - - .

116 115 114 ", **-,-

113 112 "- - -- - - . - - .-

111 z 110 109 10t 107 106 I ..... "* 2 105 104 103 102 101 100 99 98 97 96 95 .. . -. . . . . -i -i. . ... i .... i-.. I .. . .. .. . *W .. M.. . .. 1 *. . .i.

749Cl* 7500 7510 7520 7530 7540 7550 7560 7570 7580 7590 7600 7610 7620 7630 7640 7650 INDICATED FLOW - GPM ALERT RANO --Area IsW 3-4--6 ACTION RANGE: Arem Outside 1-2-3-4

4th 0Ye Planter Columbia Generating Station 4th 10-Vewteml (Relief Requests Only)

Relief Request - RP03 (Contd.)

AM E DATA SHEET - GM B Test RCIC-P-1 ACCEPTANCE CRITERIA 1335-au IM 121 1325 IM Un 12" im IM1 II 1175 11NO l1is U

1120 5

I1ls 1101 13 1075 106 100 4 "S

4410 4430 44S0 4470 44W 4510 4S30 4SSO 470 4590 PUMP/TUFSNE SPEED (RPM)

ACTION RANGE a Area Outside 1-2-3-4

IST Pmr am Plan Columbia Generating Station Pag 21 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RP04 Proponed Afterna9 In Accordance with 10 CFR SO.5g(aX3XI)

Alternative Provides Acceptable Level of Quality and Safety

,AMC Code 92=200ne AAM9*

Pump Code Class Pump Group Nu mSts RHR-P-2A2 AM52, Number _

RHR-P-2A 2 A M521, SH I RHR-P-2B 2 A M521, SH 2 Residual Heat Removal RHR-P-2C 2 A M521, SH 3 HPCS-P-1 2 I M20 High Pressure Core Spry

=-, -I1771 7,'Xvý-7-71 4'-!

77,= i-F.77ý777, The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code.

/lmlAlWW"Code R elom ISTB-351j0bW1L. Ranae. The full- scale range of each analog instrument shall be not greater than three times the reference value.

Reason for Reoues Installed test gauges used to measure the pump discharge pressure, which is used to determine differential pressure, do not meet the Code range requirements. Residual Heat Removal (RHR) and High Pressure Core Spray (HPCS) Pumps discharge pressure instruments (RHR-PT-37A, RHR-PT-378, 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. Relief is required for Group A, Group B inservice test and preservice test only. Temporary test gauges meeting the Code requirements shall be used for the comprehensive test.

Proposed Aftwmaidus 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 Date Acquisition Data (TDAS) points listed below for each pump. TDAS data averages 100 readings with a reading taken each second.

1. ISTB-3510(a) and ISTB-3510(bX1) 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 Code range requirement is to ensure reading accuracy and repeatability of test data.

iST Program Plan Columba Generat Statn Page 22 of 40 4th 10-Y intearv(Relief Requests Only)

Relief Request - RP04 (Contd.)

2. Since the TDAS data is being obtained to an accuracy of t1% of full scale, it consistently yields measurements more accurate than would be provided by itrument meeting the Code instrument accuracy requirement of f 2% of full scale and range requirement of three times the reference value. Equivalent Code accuracy being obtained by TDAS measurements is calculated in the table below.

• Rof. Instrument Test Instrument Range Value Loop Equivalent Code Pump Parameter I.D. (PSIG) (PSIG) Accuracy Accuracy RHR-P-2A Discharge RHR-PT-:37A 0-6. 0 136

• 1%, [6/(3x136))xlOO Pressure TDAS PT 155 t 6 psig =1.47%

RHR-P-2B Discharge RHR-PT-378 0-600 148

• 1%, [6/(3x148)jx1OO Pressure TOAS PT 076 - 8 Pslg =1.36%

RHR-P-2C Discharge RHR-PT-37C 0-400 143 t 1%, j6/(3x143)1x100 Pressure TOAS PT 091 16 EN =1.40%

HPCS-P-1 Discharge HPCS-PT-4 0-1500 465 + 1%, [15/(3x465)jx1OO

.... ___Pressure TDAS PT 107 .... *15psig =1.08%

• The above table reflects latest reference values as specified in the implementing procedures. This table win not be updated to reflect small changes in future reference values.

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 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.

3. The range of the pressure transmitters (PTs) 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 1400 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 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 replacement would have to be used due to the above identified reasons of replacing a PT with one not suited 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.

1ST Prowam Plmn Columbia Generating Station P 23 of 40 4th 10-Year Interval (Relief RequestS Only)

Relief Request - RP04 (Contd.)

4. NUREG-1482, Revision 2 Section 5.5.1 states that 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 Code, the [NRC] staff may grant relief when the combination of the range and accuracy yields a reading that is at least equivalent to that achieved using instruments that meet the 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 Comprehensive tests).

TDAS data will consistently provide acceptable accuracy to ensure that the pumps are performing at the flow and pressure conditions to fulfill their design function. TOAS data Is sufficiently accurate for evaluating pump condition and in detecting -pump degradation. The effect of granting this relief request will have no adverse impact on plant and public safety. Test quality will be enhanced by obtaining slightly better, more repeatal data.

2ur0tio Of PA*O Astwnathm Fourth 10 year interval.

This relief was granted for the third 10 year interval. NRC approval was documented in a letter dated March 23, 2007 (ADAMS Accession Number ML070600111, TAC No. MD3538) for Relief Request No. RPO5.

IST Proim Pla Columbia Generatinig Station Pag 24 of 40 4th 10-Year Intrval (ORele Requests Only)

Relief Request - RPOS In Accordanc. with 10 CFR S0.55SaX3XIi)

- Hardship or Unusual Difficulty Without Compensating Increase in Level of Quality or Safety -

-- 2=

Pump Code Class Pump Group P&ID Dwg. No. System(s)

SLC-P-IA 2 B M522 Stk LUquid 2 B M522 Control SLC-P-1B Anliabe gf &W ndMAdded The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code Applicalbe Code Roguiryameat Subsection ISTB-3550. 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 date.

Subsection ISTB-5300(a). (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 2 min. 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. (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.

Reason for Raueatl 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 unnecessary burden which would provide no additional assurance of determining pump operational readiness.

IST Prograr Plan' Columbia Generating Station P 25 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RPOI(Contd.)

- UWSU NUREG-1482, Revision 2 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 in 2 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 Code requirements would be a hardshe~.

Pump flow rate will be determined by measuring the volume of fluid pumped and dividing 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 the 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.

The test tank fluid volume is approximately 236 gallons. The measured flow rate Is approximately 43 gpm. The accuracy of the level reading Is +/- 1/8 inch. The accuracy of volume or level change is t1/4 inch (1/8 inch at initial level and 1/8 inch at final level). The pump is required to be run for a minimum time to ensure that an 18 inch change of test tank level has occurred. This is to ensure that the Code required accuracy for flow rate measurement of t2 percent is satisfied. A 2% error over 18 inches corresponds to 0.36 inches that is greater than 0.25 inches. The test methodology used to calculate pump flow rate will provide results consistent with Code requirements. This will provide adequate assurance of acceptable pump performance.

Calculation methods are specified in the surveillance procedures for the Standby Liquid Control Pumps, and meet the quality assurance requirements for the Columbia Generating Station.

Duration Of Pro9ose A~MMti Fourth 10 year interval.

Similar relief was granted for the third 10 year interval. NRC approval was documented in a letter dated May 15, 2007 (ADAMS Accession Number ML071010344, TAC No. M03548) for Relief Request No. RP06.

4ST 1-ar Int Columbia Generating Station Pop 26 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RP06 In Accordance with 10 CFR 50.55(a(X3XI)

- Alternative Provides Acceptable Level of Quality and Safety -

ASME Code CMM Affgte Deg Basis Pump Code Class Pump Group Accident Flow Test Flow Rate (GPM) rate (GPM)

FPC-P-1A 3 A *575 595 to 605 FPC-P-1B 3 A *575 595 t0 605 HPCS-P-1 2 B 6M 0p 65.0 to 6690 HPCS-P-2 3 A *1022 1030 to 1180 LPCS-P- . 2 B 5625@I22p 6435 to 6830 RCIC-P-1 2 a 600 610 to 628 RHR-P-2A 2 A 7034 0 0 psid 7493 to 7550 RHR-P-2B 2 A 70 a 0 e!!5 7493 to 7550 RR-P-2C 2 A 7034 0 0 psid 7493 to 7650 SLC-P-IA 2 B 41.2 GE 41.49 SLC-P-1B 2 8 41.2 GE 41.49 SW-P-1A 3 A *8928 9350 to 10270 SW-P-IB 3 A 8880 9350 to 10270

• These values are design flow rates rather than design basis accident flow rates.

/m-m 7 7 Code it The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code.

Aplnabte Code Roim m IST 123WI. Comprehensive Test Procedure refers to Table ISTB-5121-1 "Centrifugal Pump Test Acceptance Cdteia" that requires "Required Action Range" High limit of 3% above the established reference value for the measured hydraulic value of differential pressure or flow rate for the Comprehensive Test.

S-,L, Comprehensive Test Procedure refers to Table ISTB-5221-1 Vertical Line Shaft Centrifugal Pump Test Acceptance Criteria that requires "Required Action Range" High limit of 3%

above the established reference value for the measured hydraulic value of differential pressure or flow rate for the Comprehensive Test.

lST Program Plan Columbia Gonerating Station P 27 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RPW (Contd.)

I, Comprehensive Test Procedure refers to Table ISTB-5321-2 Reciprocating Positive Displacement Pump Test Acceptance Criteria that requires "Required Action Range" High limit of 3%

above the established reference value for the measured hydraulic value of discharge pressure or flow rate for the Comprehensive Test.

For some comprehensive pump tests, Energy Northwest had difficulty in Irmpementing the high required action range limit of 1.03% above the established hydreul parameter reference value due to normal data scatter. Energy Northwest had to develop contingency plans in the pump operability surveillance procedures In the event the pump enters the action high range and is declared Inoperable and applicable Technical Specification LCO entered for reasons other than a pump degradation issue.

Based on the sinilar difficulties experienced by other Owners, ASME OM Code Case OMN-19 was developed and has been published in the ASME OM-2012 edition. The white paper for this code case, Standards Committee Ballot 09-810, record 09457, discussed the impact of instrument inaccuracies, human factors involved with setting and measuring test parameters, readability of gauges and other riscellaneous factors on the ability to meet the 1.03% acceptance criteria. Industry operating experience is also discussed in the white paper.

Code Case OMN-19 has not been approved for use inRG 1.192, "Operations and Maintenance Code Case Acceptability, ASME OM Code."

Columbia Generating Station proposes to use the ASME OM Code Case OMN-19 as published in ASME OM-2012 edition for the fourth ten year interval of IST Program. The 2012 edition of Operation and Maintenance of Nuclear Power Plants, was approved by the ASME Board on Nuclear Codes and Standards on December 21, 2012. ASME OMN-19 code case allows the use of a multiplier of 1.06 times the reference value in lieu of the 1.03 multiplier for the comprehensive pump test's upper "Acceptable Range" critera and "Required Action Range, High" criteria referenced in the applicable ISTB test acceptance criteria tables ISTB-5121-1, ISTB-5221-1, and ISTB-5321-2.

As stated In the Standards Committee Ballot white paper, this issue was also discussed at the ASMEJNRC special meeting on June 4h, 2007. The NRC questioned the basis for the upper required action limits. The inaccuracies that are the basis for the change as discussed In the white paper are summarized below.

1. Instrument Inaccuracies of measured hydraulic value.

2. Instrument inaccuracies of set value and its effect on measured value.

3. Instrument Inaccuracies and allowed tolerance for speed.

4. Human factors involved with setting and measuring flow, D/P, and speed.

5. Readability of Gauges based on the smallest gauge Increment.

6. Miscellaneous Factors.

iST Prorm Ple Columbia Generating Station P 28 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RP06 (Contd.)

The above discussed inaccuracies associated with obtaining the comprehensive pump test hydraulic data may easily cause the measured value to exceed the existing code allowed upper required action limit of 3%. The new upper limit of 6% as approved in the code case OMN-19 will eliminate declaring the pump inoperable and entering unplanned Technical Specification LCO.

The mandatory Appendix V pump periodic verification test program has been published in ASME OM-2012 edition. This mandatory appendix contains requirements to augment the rules of subsection ISTB for inservice testing of pumps. It also states that the Owner is not required to perform a pump periodic verification test if the design basis accident flow rate In the Owner's safety analysis Is bounded by the comprehensive pump test or Group A test. As specified in the pump table above, the quarterly Group A or B and biennial comprehensive tests bound the verification of pump design basis flow rate and associated differential pressure or discharge pressure for positive displacement pumps.

Using the upper limit of 1.06 times the reference value in lieu of the 1.03 multiplier for the comprehensive pump test's upper "Acceptable Range' criteria and *Required Action Range, High" criteria referenced in the applicable ISTB test acceptance criteria tables will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.

Each pump performance Is also monitored by subsection IST1 required quarterly applicable Group A or Group B test that verifies operational readiness of the pump. The quarterly Group A or B pump test and biennial comprehensive pump test bounds the verification of pump design basis flow rate and associated dtfferential or discharge pressure as applicable.

DurMon gmPMogM Alen Fourth 10 year interval.

None

1. Code Case OMN-19, Alternative Upper Limit for the Comprehensive Pump Test. Published In ASME OM-2012 Edition.

2. Division 1, Mandatory Appendix V Pump Periodic Verification Test Program. Published In ASME OM-2012 Edition.

3. White Paper for ISTB Code Change, December / 2007, [Standards Committee Ballot 09-610, Record 09-657) Change C, A relaxation of the high required action range for the Comprehensive Pump Test Hydraulic Parameters (1.03 to 1.06)

iST 9w f" Columbia Generating Station Page 29 of 40 4thnteval(Relief 0-Yar Requests Only)

Relief Request - RVOI ReiRe- Request In Aecodance with 10 CFR S.Wens)(SI)

- Inservice Testing Impractalty -

ASME Cde aMMA9WM ffut Affected Valv*s Class Cat. Function System(s)

CVB-V-IAB, 2 AC To break vacuum on the drywell to suppression CVB-V-ICD, chamber downcomers and to limit steam leakage CVB-V-1EF, from the downcomer to the wetwel gas space.

CVB-V-IGH, Primary Containment CVB V.JLM, Cooling and Purge CVB-V-INP, CVB-V-IQR, CVB-V-IST hNNOW Code 9d" and MMA The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code Agglicabile Code Reguirement OM Subsection ISTC-3630, Leakage Rate for Other Than Containment Isolation Valves.

imorlticality of omuisnce These check valves cannot be tested individually therefore, assigning a limiting leakage rate for each valve or valve combination Is not practical.

Burdn Cause kv ComoUManca Subsection ISTC-3630 requires Category A valves, other than containment isolation valves, to be individually 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.

pudui AM sagWWI* n for Use These valves will be leak tested in accordance with Columbia Generating Station Technical Specifications SR 3.6.1.1.2, SR 3.6.1.1.3, and SR 3.6.1.1.4 during refueling outages.

4ST Program Pint Columbia Generating Station P 30 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RVOI (Contd.)

Technical Specifications 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.

Technical Specifications 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-drywall 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.

Technical Specifications 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, exercised, and tested in the open direction using a torque wrench per Technical Specification SR 3.6.1.7.1, SR 3.6.1.7.2, and SR 3.6.1.7.3. In accordance with a separate commitment, the valves are visually inspected each refmling outage.

aualftfstf InMat The leakage criteria and cormective actions specified in the Columbia Generating Station Technical Specifications SR 3.6.1.1.2, SR 3.6.1.1.3, and SR 3.6.1.1.4 combined with visual examination of valve seats every refuel outage provides adequate assurance of the relief valve assembly's ability to remain leak tight and to prevent a suppression pool bypass. Thus, proposed alternatlve provides adequate assurance of material quality and public safety.

Duration m ft ggm Alte ve Fourth 10 year interval.

This relief was granted for the third 10 year interval. NRC approval was documented in a letter dated May 15, 2007 (ADAMS Accession Number ML071010344, TAC No. MD3549) for Relief Request No.

RVO1.

Letter dated February 9, 2007, Carl F. Lyon (NRC) to J. V. Parish (Energy Northwest), "Columbia Generating Station - Issuance of Amendment RE: Suppression Chamber-to-Drywell Vacuum Breakers and Drywell-to-Suppression Chamber Bypass Leakage Test (TAC No. MD1225)".

1ST PO-W* Man Columbia Generating Station P 31 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RV02 Proposed Ahltft In Accordance with 10 CFR 50.S5(s)X3Xl)

- Alternative Provides Acceptable Level of Quality and Safety -

am ode ominMe Aff Affected Valves Class C.t. Function nssxsL)

PSR-V-X73-1 2 A PSR-V-X80-1 2 A PSR-V-X83-1 2 A PSR-V-X77A1 I A PSR-V-X82-1 2 A Containment Isolation Post Accident Sampling PSR-V-X84-1 2 A PSR-V-X77A3 1 A PSR-V-X82-7 2 A PSR-V-X88-1 2 A V77-M7=77, ýMT-rv =7 t The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code QM Subsecton ISTCw*150. SoertdOg erateMd YAMas SIM Testing Reason for Reouast Subsection ISTC-5151(c) requires the stroke time of all solenoid-operated valves to be measured to at least the nearest second. These nine PSR solenoid valves are the inboard Containment Isolation Valve for nine different penetrations 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 causing unnecessary wear on the valves and control switch with little compensating benefit.

4ST lO-rw Int Columbia Generating Station P 4th 10-Year I l (Relief Requests Only)

Relief Request - RVO2 (Contd.)

ProMo" Abktwna End BA" &Lr Un All of these solenoid valves stroke in less than 2 seconds and are considered Fast-Acting valves.

Their safety function Is to close to provide containment isolation. The stoke 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 2 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 (2 seconds), all 9 valves will be declared inoperable and corrective actions in accordance with Subsection 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 need for corrective action as required by ISTC-5151(d).

2uAWLftv/know The proposed alternate testing will verify that the valves respond in a timely manner and provide information for monitoring signs of material degradation. This provides adequate assurance of material quality and public safety.

bmm=777 m Fourth 10 year interval.

Similar relief was granted for the third 10 year Interval. NRC approval was documented In a letter dated March 23, 2007 (ADAMS Accession Number ML070600111, TAC No. MD3550) for Relief Request No. RV03.

1ST Program Plan Colu a Generating Station Page 33 of 40 4th 10-Year Interval (Relief RG quese t Only)

Relief Request - RV03 Proosed Alternativ in Accordance with 10 CFR SO.-55aX3XI)

- Alternative Provides Acceptable Level of Quality and Safety -

aSm Code 99MRonnt MfeAN Affected Valves Glsss Cat. Functi System(s)

MS-RV-IA, B, C, D I C MS-RV-24A B,C, D 1 C Overpressure Protecton Main Steam MS-RV-3A, B, C 1 C MS-RV-30 . .. . . .. ......1 C e P ro tectio n a nndd Auto O ve rpr ssu rf At MS-RV-4A, 8, C, D 1 C D "'pr~mtne System to lower reector pressure sufficient to allow tnWiatIon of Low

- - Presaur Coolant Incti (RHR, LPCI mode)

MS-RV-5B, C I C mCme Md &"do-tdWe The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code Aollicb" COde a irm e MandatorW A&Mendix I. PaffiraM 1-3310: Sequence of Periodic Testing of Class 1 Main Steam Pressure Relief Valves with Auxiliary Actuating Devices.

Mandatory AQ2endlx I. ParaoroMh 1-3310, states that tests before maintenance or set-pressure adjustment, or both, shall be performed for 1-3310(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.

'ST Pgi' p"' Columbia Generating Station P 3 of 40 4th 10-Year Interval (Relief Requests Only)

Relief Request - RV03 (Contld.)

Reasew fbr Rgaout Relief is requested from requirements for sequence of periodic testing of Class 1 Main Steam pressure relief valves with auxiliary actuating devices.

1. Remote set pressure verification devices (SPVDs) have been permanently Instaled on all eighteen Main Steam Relief Valves (MSRVs) to alow 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 MSRV's popping pressure is reached. During normal power operation, these SPVDs remain deenergized and do not interfere with normal safety or relief valve functions. Removal and replacement of the MSRVs is normally performed only for valve maintenance and not for the purpose of As-Found set pressure determination. MSRVs are removed and replaced for maintenance purposes (e.g., seat leakage, refurbishment) nominally each refueling outage. The valves which are required to be As-Found set pressure tested, as part of the Code required periodic testing, do not necessarily correspond to those required to be replaced for maintenance. Actxuts 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 Code required sequence while the drywell is inerted. Visual examinations are performed after reactor shutdown but prior to valve 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 refueling outage, it will be required to be performed during power ascension from refueling outage or by removing the valves and sending them to the vendor for as-found set pressure testing. This would require Paragraphs 1-3310(a), (d), (e), (f), and (h) tests to be performed during outage prior to Paragraphs 1-3310(b), (c) and (0)tests. Paragraph 1-3310(g) is not applicable to these valve designs.

2. "Valves" and "accessories" (actuators, solenoids, etc.) have different maintenance and test cycles due to the methods used for maintenance and testing at Columbia Generating Station as discussed in item 1, 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 Owner's seat tightness criteria, in accordance with Paragraphs 1-3310(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 1-3310(d), (e), (f), and (h)).

Paragraph 1-3310 states that tests before maintenance or set-pressure adjustment, or both, shall be performed for 1-3310(a), (b), and (c) in sequence. The remaining shall be performed after maintenance or set pressure adjustments. Valve maintenance or set pressure 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 1-1320 test frequency requirements.

4ST lO-Yea Int Columbia Generating Station P of4 4th 10-Yer Interval (Relief Requests Only)

Relief Request - RV03 (Contd.)

3. Paragraph 1-3310(f) requires determination of operation and electrical charactgrscs of position Indicators, and Paragraph 1-3310(h) requires 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 outages; the sensing elements (pressure switches) are all checked and calibrated at least once per 24 months.

Although the existing bats do not have a one-to-one cor retion to the valve or actuator tests, these calibrations and functional tests meet all testing requirements of this Subsection, and far exceed the required test frequency and testing requirements.

Praie ft M nd Basisftw URI

1. WValves- and -accessories" (actuators, solenoids, etc.) shall be tested separately and meet Paragraph 1-1320 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 refueling outage. As-found visual examination will be performed after set-pressure testing, which is out of the specified Code required sequence.

If MSRV periodic set pressure testing could not be performed at power during shutdown for refueling outage due to reactor scram it will be required to be performed during power ascension from refueling outage or by removing the valves and sending them to the vendor for as-found set pressure testing. This will require Paragraphs 1-3310(a), (d) and (a) tests to be performed during outage prior to Paragraphs 1-3310(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 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 valve's future set pressure determination.

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 at least once per 24 months during shutdowns. These tests will be credited for satisfying the requirements of Paragraph 1-3310(f).

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 1-3310(h).

1SW Progran Plan Columbia Generating Station P 36 of 40 4tho10-Year Inv= (Relief Requests Only)

Relief Request - RV03 (Contd.)

QualtSfty Imp a t Due to different maintenance and test cycles of valves and accessories and also due to methods used for testing and maintenance, It Is impractical to meet the Code required testing requirements without subjecting the valves to unnecessary challenges and increased risk of seat degradation. The requirement for testing actuators and accessories in a specific sequence does not enhance system or component operability, or in any way Improve nuclear safety. The proposed alternate testing adequately evaluates the operational readiness of these valves commensuramt with their safety function. This will help reduce the number of challenges and failures of safety relief valves and still provide timely informauon regarding operability and degradation. This will provide adequate assurance of material quality and public safety.

DQurio of PromaamdA Fourth 10 year interval.

Similar relief was granted for the third 10 year interval. NRC approval was documented in a letter dated March 23, 2007 (ADAMS Accession Number ML070600111, TAC No. MD3551) for Relief Request No. RVO4.

4ST Pro-Ym Plan Columbia Generating Station Pop 3 4th 10-Year Interval (Relief Requests Only)

Relief Request - RV04 Proposed Aktunatlv In Accordance with 10 CFR 50.SSe(aX3X))

- Alternative Provides Acceptable Level of Quality and Safety -

Affected Valves I [lss

) [ SysIsms PI-EFC-X(3?E, PI-EFC,-X37F I System(s): Process Instrumentatin for various PI-EFC-X38A, PI-EFC-X38B, system conincted to RPV PI-EFC-X38C, PI-EFC-X38D, 1 C PI-EFC-X38E, PI-EFC-X38F Function: Excess flow check valves are provided in each Instrument process line that is PI-EFC-X39A, PI-EFC-X396, C part of the reactor coolant pressure PI-EFC-X390, PI-EFC-X39E boundary. Desgn and installation of the PI-EFC-X40C, PI-EFC-X40D I C excess flow check valves at Columbia Generating Station conform to Regulatory PI-EFC-X40E, PI-EFC-X40F 2 C Guide 1.11.

PI-EFC-X41C, PI-EFC-X41D 1 C PI-EFC-X41E, PI-EFC-X41F 2 C Close: The reactor instrument line excess flow check valves dose to limit the flow in the PI-EFC-X42A, PI-EFC-X42B 1 C respective instrument lnes In the event of PI-EFC-X44AA, PI EFC X44AB, an instrument line break downstream of PI-EFC-X44AC, PI-EFC-X44AD, the EFCVs outside containment.

PI-EFC-X44AE, PI-EFC-X44AF, C PI-EFC-X44AG, PI-EFC-X44AH, PI-EFC-X44AJ, PI-EFC-X44AK, PI-EFC-X44AL, PI-EFC-X44AM PI-EFC-X44BA, PI-EFC-X44BB, PI-EFC-X448C, PI-EFC-X44BD, PI-EFC-X448E, PI-EFC-X448F, 1 C PI-EFC-X44BG, PI-EFC-X44BH, PI-EFC-X44BJ, PI-EFC-X448K, PI-EFC-X44BL, PI-EFC-X44BM PI-EFC-X61A, PI-EFC-X61B 1 C PI-EFC-X62C, PI-EFC-X62D I C PI-EFC-X69A, PI-EFC-X698, 1 C PI-EFC-X69E PI-EFC-X70A, PI-EFC-X708, PI-EFC-X70C, PI-EFC-X70D, 1 C PI-EFC-X70E, PI-EFC-X7OF PI-EFC-X71A, PI-EFC-X71B, PI-EFC-X71C, PI-EFC-X71D, I C PI-EFC-X71E, PI-EFC-X7IF PI-EFC-X72A 1 C PI-EFCX73A I.

I C

IS PlrWw Intervan 4th 10-Year Columbia (Relief Generating Requ,,-ts Only) Station Pg38of 40 Relief Request - RV04 (Contd.)

Affected Valves Class Cat. System(s) / Function PI-EFC-X74A, PI-EFC-X748, 1 C System(s): Process Instrumentation for vaious PI-EFC-X74E, PI-EFC-X74F systems connected to RPV PI-EFC-X75A, PI-EFC-X758, PI-EFC-X75C, PI-EFC-X750, I c Function: Excess flow check valves are provided in PI-EFC-X75E, PI-EFC-X75F each inrument process line that is part of the reactor coolant presure PI.EFC.X788, PI-EFC-X78C, C boundary. Design and installaon of the PI-EFC-X78F excess flow check valves at Columbia PI-EFC-X79A, PI-EFC-X798 I C Generating Station conform to Regulatory PI-EFC-X106 I C Gukde 1.11.

PI-EFC-Xl07 I C Clo: The reacto instrumren nm excess flow PI-EFC-X108 I C check valves close to limit the flow in the

- - ... respective instument lines In the event of PI-EFC-X109 I C an instrument line break downsteam of PI-EFC-X110 I C the EFCVs outside containment PI-EFC-X1 11 1 C PI-EFC-X1 12 1 C PIEFC-X1,3 I C PI-EFC-X113 1 C PI-EFC-X115 1 C __________________

WS~tIiflaaJna~aim The 2004 Edition and the 2005 and 2006 Addenda of the ASME OM Code

&Malbe CodemuMAmmn OM Subsection ISTC-3522=c1, Cateoorv C Chock Valves. If exercising is not practicable during operation at power and cold shutdowns, It shall be performed during refueling outages.

OM useton IS -700, Valve Poito VA . Valves with remote position indicators shall be observed locally at least once every 2 years to verify that valve operation is accurately indicated.

Where practicable, this local observation should be supplemented by other indications such as use of flow meters or other suitable instrumentation to verify obturator position. These observations need not be concurrent. Where local observation Is not possible, other indications shall be used for verification of valve operation.

Reason for Reouest and Basis for U 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 cold shutdown condition, in maintaining the cold 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 cold shutdown

4ST PrO-rea int Columbia Generating Station P of 40 4th 10-Year Interval (Relief Requtet. Only)

Relief Request - RY04 (Contd.)

condition. Additionaly, the reactor instrument lines are assumed to maintain integrity for all accidents except for the Instrument Line 8reak Accident (ILBA) as described In Final Safety Analysis Report (FSAR) Subsection 15.6.2. The reactor instrument lines at Columbia Generating Station 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 Coluria Generating Station safety analysis. These EFCVs dose to imk 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 the amended Technical Specification SR 3.6.1.3.8.

The GE (General Electric) Licensing Topical Report NEDO-32977.A dated November 1998 (Reference 2), and associated NRC safety evaluation, dated March 14, 2000, prves the basis for this relief. The report provides Justification for relaxation of the testing frequency as described in the amended Technical Specification 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. Based on 15 years of testing (up to year 2000) with only one (1) failure, the Columbia Generating Station revised Best Estimate Failure Rate Is 7.9E-8 per hour; less than the industry average of 1.01E-7 per hour. There have been no failures since year 2000. Technical Specification amendment request for SR 3.6.1.3.8 was reviewed by the NRC staff in safety evaluation (SE) dated February 20, 2001 (Reference 3).

Failure of an EFCV, though not expected as a result of the amended Technical Specification change, is bounded by the Columbia Generating Station 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 Reference 3, the NRC staff concluded that the increase in risk associated with the relaxation of EFCV testing is sufficiently low and acceptable.

Energy Northwest requests relief pursuant to 10 CFR 50.55a(a)(3)(i) to test reactor instrument line excess flow check valves in accordance with the amended Technical Specification 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 Columbia Generating Station Corrective Action Program.

I= i A,-77-- - F175.7 -

Fourth 10 year interval.

ST Program Pn Columbia Generating Station P of 40 4th 10-Veer interval (Relief Requests Only)

Relief Request - RV04 (Contd.)

This relief was granted for the third 10 year interval. NRC approval was documented In a letter dated March 23, 2007 (ADAMS Accession Number ML070600111, TAC No. MD3552) for Relief Request No. RVO5.

1. FSAR 15.6.2

2. Letter BWROG-00069, dated June 14, 2000, from W.G. Warren, (BWR Owners Group) to Office of Nuclear Reactor Regulation, "Transunttal of Approved GE Licensing Topical Report NEDO-32977-A, Excess Flow Check Valve Testing Relaxation", dated November 1998 3 Letter dated February 20, 2001, Jack Cushing (NRC) to JV Parish (EN), 'Columbia Generating station - Issuance of Amendment RE: Technical Specifications Surveillance Requirement 3.6.1.3.8 (TAC NO. MB0421 )"