NG-11-0365, Relief Request VR-02 Regarding In-Service Testing of Safety/Relief Valves
| ML112720486 | |
| Person / Time | |
|---|---|
| Site: | Duane Arnold  |
| Issue date: | 09/29/2011 |
| From: | Wells P NextEra Energy Duane Arnold |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NG-11-0365 | |
| Download: ML112720486 (11) | |
Text
I ;
1_-______ _
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DUANE September 29,2011 u.s. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D.C. 20555-0001 Duane Arnold Energy Center Docket 50-331 Renewed Op. License No. DPR-49
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ARNOLD NG-11-0365 10 CFR 50.55a Relief Request VR-02 Regarding In-Service Testing of Safety/Relief Valves Pursuant to 10 CFR 50.55a(a)(3)(i) and (f)(4)(iv), NextEra Energy Duane Arnold, LLC, (hereafter, NextEra Energy Duane Arnold) hereby requests NRC approval of relief from the testing requirements of ASME OM Code-2001, Appendix I, paragraphs 1-1320(a) and 1-3410(d), including ISTC-5113 and ISTC-5114. This relief is requested for the remainder of the fourth 10-year interval of the Inservice Testing (1ST) Program for the Duane Arnold Energy Center (DAEC), which began on February 1, 2006. The enclosure to this letter contains that request for relief.
NextEra Energy Duane Arnold requests approval of this request by the end of September, 2012 to support the next refueling outage at the DAEC.
This letter contains no new or revised commitments.
ave any questions, please contact Steve Catron at (319) 851-7234.
Peter Wells Vice President, Duane Arnold Energy Center NextEra Energy Duane Arnold, LLC Enclosure NextEra Energy Duane Arnold, LLC, 3277 DAEC Road, Palo, IA 52324
Enclosure to NG-11-0365 Page 1 of 10 Valve Relief Request - VR-02 Proposed Alternative Testing for ASME Class 1 Pressure Relief/Safety Valves In Accordance with 10 CFR 50.55a(a)(3)(i) and (f)(4)(iv)
Systems:
Nuclear Boiler System Automatic Depressurization (ADS) and Low-Low Set (LLS) System Valves:
PSV4400 Main Steam Line A ADS Relief Valve PSV4401 Main Steam Line A LLS Relief Valve PSV4402 Main Steam Line B ADS Relief Valve PSV4405 Main Steam Line C ADS Relief Valve PSV4406 Main Steam Line D ADS Relief Valve PSV4407 Main Steam Line D LLS Relief Valve Category:
B/C Class: 1 Function:
The Safety/Relief Valves (SRVs) provide automatic overpressure protection for the nuclear boiler system, thereby preventing failure of the nuclear process barrier (i.e.,
reactor coolant pressure boundary). Each SRV is self-actuating at its prescribed set-point and resets at approximately 50 psi below its lift set-point. (DAEC Updated Final Safety Analysis Report (UFSAR) Section 5.2.2)
The Automatic Depressurization System (ADS) utilizes four of the six SRVs provided in the nuclear boiler system to accomplish reactor vessel depressurization. The purpose of the ADS is to provide an automatic means of reducing reactor pressure for events such as pipe breaks or reactor loss of water level transients when the HPCI system is unable to maintain reactor water level. The pressure reduction enables low pressure make-up systems such as Low Pressure Coolant Injection (LPCI) and Core Spray to inject additional makeup water into the vessel to restore or maintain water level preventing overheating of the fuel cladding. (DAEC UFSAR Section 6.3.2.2.2)
The Low-Low Set (LLS) System utilizes the two remaining SRVs provided in the nuclear boilers system that are not used for the ADS function to mitigate the induced high frequency loads on the primary containment (torus) and the thrust loads on the SRV discharge lines and tailpipes. This reduces the possibility of a SRV tailpipe rupture occurring inside the torus above the suppression pool water level; thereby creating a bypass of the pressure suppression function. The LLS System automatically controls reactor pressure by opening and closing the LLS SRVs in the relief mode over a wider band of reactor pressure than the safety mode. The LLS valves are the two SRVs with the lowest safety mode pressure relief setpoints. This reduces the number and frequency of SRV actuations allowing the SRV discharge line vacuum relief valves time
Enclosure to NG-11-0365 Page 2 of 10 to clear the discharge lines of water, thus lowering the thrust loads. (DAEC UFSAR Section 5.4.13)
In addition, each SRV may be operated in the relief mode from the Main Control Room with individual AUTO/OPEN switches and selected SRVs may be similarly operated from the Remote Shutdown Panel outside the Main Control Room. This capability allows the SRVs to be utilized for reactor vessel pressure control under emergency conditions.
The six SRVs are Target Rock Three-Stage, Model 7467F design. The SRVs are dual-function valves capable of being independently opened in either the safety or relief mode of operation. The ADS SRVs are identical in construction to the LLS SRVs. Each valve is a pilot-controlled, pneumatically opened, spring shut, reverse-seated globe valve. It can be operated either as a self-actuated pressure relief function or a remote-actuated pressure control function.
The SRV consists of three main sections, the pilot valve, the remote actuator, and the main valve. Reactor vessel pressure is felt on the top and bottom of the main valve piston, and on the pilot valve bellows via the pilot sensing port. Since reactor vessel pressure is equalized across the main valve piston due to the drilled orifice, it is the main valve spring and differential pressure across the main disc, which keeps the main disc seated. When reactor vessel pressure reaches the self-actuated pressure relief function opening set-point, the pilot valve is forced open against spring pressure, allowing steam to flow into the chamber above the second stage piston. Steam pressure exerted on the second stage piston causes the second stage disc to unseat, providing a relief path for steam above the main disc. Since the steam can escape through the passage in the valve body faster than it can be admitted through the small main piston orifice, pressure above the main piston will decrease. Pressure will continue to decrease until reactor vessel pressure acting on the under side of the main piston overcomes the spring pressure and forces the main disc off its seat. When reactor system pressure decreases to approximately 50 psi below the self-actuated pressure relief function opening set-point, the pilot valve will reseat and the main valve spring pressure will reseat the main disc.
Remote actuation of an SRV may be accomplished by its hand-switch located in the Main Control Room, selected switches on the Remote Shutdown Panel, or by automatic initiation signals (ADS or LLS). Upon receipt of a remote initiation signal from any of these sources, the SRVs solenoid operating valve (SOV) is energized and 90-psi nitrogen pressure is directed to a diaphragm near the top of the SRV. This causes the diaphragm and the attached rod to be forced downward. The rod then makes physical contact with the second stage piston causing the second stage disc to unseat. The remainder of the valve operation is the same as for self-actuation function previously described. Removal of the remote initiation signal allows nitrogen pressure to vent off of the diaphragm via the exhaust port of the SOV, thus permitting the spring to reseat the main disc.
Test Requirement:
2001 Edition and the 2002 and 2003 Addenda of the ASME OM Code.
Enclosure to NG-11-0365 Page 3 of 10 The main steam relief valves are dual function safety/relief valves that operate as both a pilot operated relief valve (overpressure protection mode) and a power-operated relief valve (manual/ADS/LLS mode). The SRVs are categorized as Category B and Category C valves in the Inservice Testing Program. The Category of C is consistent with the pilot operated relief valve function and is tested per Appendix I of the ASME OM Code.
Category B is consistent with a power-operated relief valve and is tested per Section ISTC-5100 of the ASME OM Code.
Appendix I Section I-1320, Test Frequencies, Class 1 Pressure Relief Valves (a) 5-Year Test Interval. Class 1 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. This 20% shall consist of valves that have not been tested during the current 5-year interval, if they exist. The test interval for any individual valve shall not exceed 5 years.
(b) Replacement With Pretested Valves. The Owner may satisfy testing requirements by installing pretested valves to replace valves that have been in service, provided that:
(1) For replacement of a partial complement of valves, the valves removed from service shall be tested prior to resumption of electric power generation; or (2) For replacement of a full complement of valves, the valves removed from service shall be tested within 12 months of removal from the system.
(c) Requirements for Testing Additional Valves. Additional valves shall be tested in accordance with the following requirements.
(1) For each valve tested for which the as-found set-pressure (first test actuation) exceeds the greater of either the +/-tolerance limit of the Owner-established set-pressure acceptance criteria of I-1310(e) or +/-3% of valve nameplate set-pressure, two additional valves shall be tested from the same valve group.
(2) If the as-found set-pressure of any of the additional valves tested in accordance with I-1320(c)(1) exceeds the criteria noted therein, then all remaining valves of that same valve group shall be tested.
(3) The Owner shall evaluate the cause and effect of valves that fail to comply with the set-pressure acceptance criteria established in I-1320(c)(1) or the Owner-established acceptance criteria for other required tests, such as the acceptance of auxiliary actuating devices, compliance with Owners seat tightness criteria, etc. Based upon this evaluation, the Owner shall determine the need for testing in addition to the minimum tests specified in I-1320(c) to address any generic concerns that could apply to valves in the same or other valve groups.
Appendix I Section I-3410, Class 1 Main Steam Pressure Relief Valves with Auxiliary Actuating Devices (d) Each valve that has been maintained or refurbished in place, removed for maintenance and testing, or both, and reinstalled shall be remotely actuated at reduced or normal system pressure to verify open and close capability of the valve before resumption of electric power generation. Set-pressure verification is not required.
Enclosure to NG-11-0365 Page 4 of 10 Section ISTC-5113, Valve Stroke Testing (a) Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.
(b) The limiting value(s) of full-stroke time of each valve shall be specified by the Owner.
(c) The stroke time of all valves shall be measured to at least the nearest second.
(d) Any abnormality or erratic action shall be recorded (see ISTC-9120) and an evaluation shall be made regarding need for corrective action.
(e) Stroke testing shall be performed during normal operating conditions for temperature and pressure if practicable.
Section ISTC-5114 Stroke Test Acceptance Criteria Test results shall be compared to the reference values established in accordance with ISTC-3300, ISTC-3310, or ISTC-3320.
(a) Valves with reference stroke times of greater than 10 sec shall exhibit no more than 125% change in stroke time when compared to the reference value.
(b) Valves with reference stroke times of less than or equal to 10 sec shall exhibit no more than I50% change in stroke time when compared to the reference value.
(c) Valves that stroke in less than 2 sec may be exempted from ISTC-5115(b). In such cases the maximum limiting stroke time shall be 2 sec.
Basis for Relief from I-1320(a) and I-3410(d):
Reason for Relief:
This fourth 10-year Interval request for relief is based on Appendix I of the ASME OM Code-2001 Edition to 2003 Addenda. Exercising of the SRV after reinstallation can only be performed during reactor startup when there is sufficient steam pressure to actuate the main disk. Past history indicates that the main disks may not re-seat properly after being exercised during reactor startup resulting in steam leakage into the suppression pool. This leakage results in a decrease in plant performance and the potential for increased suppression pool temperatures which could force a plant shutdown to repair a leaking SRV. Past operating history indicates that the exercising performed during reactor startup is of no significant benefit in ensuring the proper operation of the individual SRV subassemblies.
This relief request also proposes to implement Code Case OMN-17 "Alternate Rules for Testing ASME Class 1 Pressure Relief/Safety Valves." OMN-17 states in Section (a) that safety valves shall be tested at least once every 72 months (6 years) with a minimum of 20% of the SRV group being tested within any 24-month interval. This 20% shall consist of valves that have not been tested during the current 72-month interval, if they exist.
The test interval for any individual valve that is in service shall not exceed 72 months except that a 6-month grace period is allowed to coincide with refueling outages to accommodate extended shutdown periods.
Enclosure to NG-11-0365 Page 5 of 10 General Change Justification:
Leaking SRVs create operational problems associated with the suppression pool. SRV leakage increases both pool temperature and level, requiring more frequent use of the Residual Heat Removal (RHR) System to maintain the corresponding limits for the suppression pool in the plants Technical Specifications (TS).
The SRV pilot assemblies removed during the refuel outage are tested at an offsite facility. The as-found testing is performed prior to the resumption of power operation from that refuel outage, meeting the OM code requirements. The valves are refurbished, as necessary, to meet the acceptance criteria of zero leakage, and are certified in writing as being leak free. The valves are then reinstalled in the plant in a subsequent refuel outage and proper pilot operation is confirmed through leak rate testing of the pilot air operators and associated accumulator piping followed by manual lift at reactor power.
Several aspects of SRV design and operation can contribute to valve leakage. As mentioned earlier, these include test pressure, pilot valve disc and rod configuration, and overall system and valve cleanliness. Actuation of the SRVs after laboratory testing by any means allows these contributors to impact the ability of the valve to re-close completely. NextEra Energy Duane Arnold has made significant efforts to minimize the effects of these contributors. In1999 the DAEC Technical Specifications were changed to permit an as-found tolerance of +/-3% and +/-1% as-left tolerance on the SRV opening setpoints. Since that time, the DAEC has had no SRV setpoint failures and only one instance of seat leakage during testing at the offsite facility in 2009. There have been two instances of valve leakage during power operation; a pilot valve leak in 2004 and a second stage leak in 2010. This recent event occurred shortly after performance of the in-situ test at reduced system pressure and is believed to be a contributing cause of the valve failure.
NextEra Energy Duane Arnold currently uses ASME OM Code 2001 through 2003 addenda section I-1320 "Test Frequencies, Class I Pressure Relief Valves." This establishes the five year frequency for SRV testing. NextEra Energy Duane Arnold proposes to use Code Case OMN-17 "Alternate Rules for Testing ASME Class 1 Pressure Relief/Safety Valves." This Code Case changes the frequency to six years, including a 6 month grace period, to coincide with the 24-month refueling cycle at DAEC.
Code Case OMN-17 has been included in the 2009 Edition of the ASME Code.
Section I-3410(d) of this Code edition requires manual actuation testing at reduced or normal system pressure following reinstallation after maintenance and/or testing. The 2004 Edition of the OM Code (no Addendum), does not require Owners to stroke SRVs at reduced or normal system pressure following maintenance or testing. NextEra Energy Duane Arnold proposes to utilize this later edition of the Code to support future testing of the SRVs.
Additionally, reducing challenges to the SRVs is a recommendation of NUREG-0737; "TMI Action Plan Requirements," Item II.K.3.16. This recommendation is based on a stuck-open SRV being a possible Loss of Coolant Accident (LOCA). This relief request is consistent with that NRC recommendation.
Enclosure to NG-11-0365 Page 6 of 10 Proposed Alternative Test:
As an alternate to the testing required by ASME OM Code-2001, Appendix I, paragraph I-3410(d), NextEra Energy Duane Arnold proposes to actuate the SRVs in the relief mode at the certified test facility. A test solenoid valve will be energized, the actuator will stroke, and the 2nd stage rod movement will be verified. This test will verify that, given a signal to energize the solenoid valve, the 2nd stage disc rod will travel to unseat the 2nd stage disc. The 2nd stage function will be recorded in the test documentation package for future reference, as needed. Alternate testing is justified since the remaining segments of the SRV relief mode of operation are verified by other tests. The ability of the pilot disc to open is demonstrated in the safety mode actuation bench test. The integrity of the pneumatic and solenoid system for the SRVs is verified by performance of post maintenance leak rate testing, continuity testing, and a functional test of the solenoid valve while detached from the SRV. Automatic valve actuation is proven by Logic System Functional Tests which include verification that the SOV is energized by the automatic signal. The actuator to main body joint is inspected during ISI VT-2 exam performed prior to startup. The above proposed surveillance and testing of the SRVs and associated components provide reasonable assurance of adequate valve operation and readiness.
Following installation, the electrical and pneumatic connections will be verified by energizing the SOVs using the respective control switches and inspecting the pneumatic actuator for movement and leakage (so-called dry lift test). While this test will actuate the SRV second stage, operating experience at other plants indicates that it does not initiate second stage leakage or otherwise damage the valve when performed with no steam pressure; thus, making it a better alternative test to an in-situ steam test during reactor startup.
NextEra Energy Duane Arnold proposes to implement Code Case OMN-17 that requires in section (a) a 72-month test interval for Class 1 pressure relief valves with a minimum of 20% of the SRV group being tested within any 24-month interval. This 20% shall consist of valves that have not been tested during the current 72-month interval, if they exist. The test interval for any individual valve that is in service shall not exceed 72 months except that a six month grace period is allowed to coincide with refueling outages to accommodate extended shutdown periods. The removed main steam relief valves will be sent for as-found testing to the off-site test facility. Each main steam relief valve will then be disassembled and inspected for abnormal wear and the specific concerns documented in General Electric Company Service Information Letters (SIL)
No. 196, Supplement 17 and No. 646, References 5 and 6 respectively. The post-maintenance tests required by Appendix I, Section I-3310 will be conducted at the off-site testing facility. As part of implementation of this relief request, NextEra Energy Duane Arnold will institute measures to assure that each main steam relief valve will be disassembled and inspected prior to being place on the new 72-month interval.
Testing will be performed as provided in ASME Operation and Maintenance Code Case OMN-17, Alternative Rules for Testing ASME Class 1 Pressure Relief/Safety Valves, as stated below.
Enclosure to NG-11-0365 Page 7 of 10 Test Frequencies, Class 1 Pressure Relief Valves (a) 72-Month Test Interval. Class 1 pressure relief valves shall be tested at least once every 72 months (6-years), starting with initial electric power generation.
A minimum of 20% of the valves from each valve group shall be tested within any 24-month interval. This 20% shall consist of valves that have not been tested during the current 5-year interval, if they exist. The test interval for any individual valve shall not exceed 72 months except that a 6 month grace period is allowed to coincide with refueling outages to accommodate extended shutdown periods.
(b) Replacement With Pretested Valves. The Owner may satisfy testing requirements by installing pretested valves to replace valves that have been in service, provided that:
(1) For replacement of a partial complement of valves, the valves removed from service shall be tested prior to resumption of electric power generation and shall be subjected to the maintenance specified in (d); or (2) For replacement of a full complement of valves, the valves removed from service shall be tested within 24 months of removal from the system.
(c) Requirements for Testing Additional Valves. Additional valves shall be tested in accordance with the following requirements.
(1) For each valve tested for which the as-found set-pressure (first test actuation) exceeds the greater of either the +/-tolerance limit of the Owner-established set-pressure acceptance criteria or +/-3% of valve nameplate set-pressure, two additional valves shall be tested from the same valve group.
(2) If the as-found set-pressure of any of the additional valves tested in accordance with (c)(1) exceeds the criteria noted therein, then all remaining valves of that same valve group shall be tested.
(3) The Owner shall evaluate the cause and effect of valves that fail to comply with the set-pressure acceptance criteria established in (c)(1) or the Owner-established acceptance criteria for other required tests (e.g. acceptance of auxiliary actuating devices, compliance with Owners seat tightness criteria). Based upon this evaluation, the Owner shall determine the need for testing in addition to the minimum tests specified.
(d) Maintenance. The Owner shall disassemble and inspect each valve after as-found set-pressure testing to verify that parts are free of defects resulting from time related degradation or service induced wear. Based on upon this inspection, the Owner shall determine the need for additional inspections or testing to address any generic concerns. As-left set-pressure testing shall be performed following maintenance and prior to retuning the valve to service.
(e) Each valve shall have been disassembled and inspected in accordance with (d) above prior to the start of the 72 month test interval. Disassembly and inspection performed prior to the implementation of this Code Case may be used.
Appendix I Section I-3410, Class 1 Main Steam Pressure Relief Valves with Auxiliary Actuating Devices (ASME OM Code 2004 Edition, no Addendum)
(d) Each valve with an auxiliary actuating device that has been removed for maintenance or testing and reinstalled after meeting the requirements of I-
Enclosure to NG-11-0365 Page 8 of 10 3310, shall have the electrical and pneumatic connections verified either through mechanical/electrical inspection or test prior to the resumption of electric power generation. Main disc movement and set-pressure verification are not required.
Basis for Relief from ISTC-5113 and ISTC-5114:
Reason for Relief:
The proposed alternatives also provide adequate assurance that valve stroke time in the power-actuated mode will be acceptable. Stroke timing of the SRVs will be performed at the test facility as described above. Currently, as-found stroke time testing is performed prior to and after performing maintenance at the test facility. After completion of maintenance, plant surveillance tests with steam at reduced pressure are performed in order to detect gross failures of the SRVs to change position. The tests performed at DAEC are not as refined as the valve response time test performed at the offsite test facility. The design requirement for the valve stroke time is 0.45 seconds, from signal initiation to valve full open in the power-actuated mode (0.40 seconds for signal initiation to start of valve motion and 0.050 seconds (50 milliseconds) for valve stroke to full open). Measuring valve stroke times to this level of accuracy in-situ at the power plant is not practical and only possible under the controlled conditions of the offsite facility. Per ISTC-5114(c), the maximum permissible valve stroke time can be up to 2 seconds.
Consequently, the in-situ test acceptance criterion becomes essentially a failure to open criterion. Therefore, the tests performed at DAEC can only detect gross failures to change position and cannot monitor for valve performance degradation between tests.
General Change Justification:
In-situ stroke timing is not useful for identifying valve degradation over several operating cycles. Rather, an in-situ exercise test will be used to ensure that the valve will function in the power-actuated mode. This test will be performed at the frequency prescribed in ISTC-3510 for power-operated relief valves. Stroke time at the test facility will demonstrate that the valve performs acceptably compared to the stroke times of known good performing valves. Since the test facility can not duplicate the electrical control system at the plant, actuation of the valve at the test facility is accomplished through a simplified electrical actuation. Observation of the end of the operating stroke at the test facility is indirect, based on evidence of steam flow and pressure, as it is at the nuclear facility, since the relief valves have no positive open indication. Although these differences may result in minor differences in measured stroke time compared to those measured when installed in the plant, the stroke times measured at the test facility will be comparable to each other and thus can be used to detect any abnormality in valve performance.
Proposed Alternative Test:
Stroke times will be measured at the test facility. Stroke times will be measured following valve rebuild. The timing will begin with the actuating electrical signal and end with the indirect indication of the end of the operating stroke. Stroke time acceptance criteria will
Enclosure to NG-11-0365 Page 9 of 10 use a pre-established reference value that represents good performance for the valve type.
An in-situ exercise test of the valve in the power-actuated mode will be performed at the frequency prescribed in ISTC-3510. The in-situ exercise test will be performed prior to the resumption of electric power generation. Main disc movement and set-pressure verification are not required.
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Conclusion:==
Based upon the above, the proposed alternatives provide an adequate assurance of quality and safety equal to that of the current Code of record. Consequently, the provisions of 10 CFR 50.55a(a)(3)(i) and (f)(4)(iv) are judged to be met.
Duration:
The proposed alternative identified in this relief request shall be utilized during the fourth 10-year IST Interval that began on February 1, 2006.
Precedents:
ASME Code Case OMN-17 has been included in the 2009 Edition of the ASME Code.
NUREG-1482, Rev. 1, Paragraph 4.3.2.1 states, "In recent years, the NRC staff has received numerous requests for relief and/or TS changes related to the stroke testing requirements for BWR dual function main steam SRVs. Both Appendix I to the ASME OM Code and the plant-specific TS require stroke testing of SRVs after they are reinstalled following maintenance activities. Several licensees have determined that in-situ testing of the SRVs can contribute to undesirable seat leakage of the valves during subsequent plant operation and have received approval to perform testing at a laboratory facility coupled with in situ tests and other verifications of actuation systems as an alternative to the testing required by the ASME OM Code and TS."
Similar relief has been approved for the Dresden and Quad Cities stations (ML081330557) and Peach Bottom units (ML081790539), which also use three-stage Target Rock SRVs. The alternative testing approved for these plants included an in-situ actuator test without live steam (dry lift test).
References:
- 2. Code Case OMN-17, Alternative Rules for Testing ASME Class 1 Pressure Relief /
Safety Valves
- 3. NUREG-1482 Rev. 1, Guidelines for Inservice Testing at Nuclear power Plants
Enclosure to NG-11-0365 Page 10 of 10
- 5. General Electric Co. Service Information Letter # 196, Supplement 17, Target Rock SRV main disc spring relaxation and tip breakage, January 5, 1996.
- 6. General Electric Co. Service Information Letter # 646, Target Rock safety relief valve failure to fully open, December 20, 2002.