1. 1 ISTOG QUESTIONS –2007 1. 5-YR Frequency of Class 1 Relief Valves A Nuclear Station has three class 1 safety valves. A Nuclear Station has three class 1 safety valves. To meet the code, one safety valve is typically sent offsite each refueling outage, tested, refurbished, sent back, and re-installed. To meet the code, one safety valve is typically sent offsite each refueling outage, tested, refurbished, sent back, and re-installed. The NPP typically has 18 month refueling outage frequencies. However, due to some shifts in scheduling, our next scheduled refueling outage (April of 2008) places the individual safety valve selected for this outage at over 5 years (5 years plus approximately one month). The NPP typically has 18 month refueling outage frequencies. However, due to some shifts in scheduling, our next scheduled refueling outage (April of 2008) places the individual safety valve selected for this outage at over 5 years (5 years plus approximately one month). We are currently required to follow the 2003 Addenda to the 2001 Edition of the Code. We are currently required to follow the 2003 Addenda to the 2001 Edition of the Code. Our Technical Specifications require the testing of these valves to be per the IST Program. Our Technical Specifications require the testing of these valves to be per the IST Program.

2. 2 ISTOG QUESTIONS –2007 1. 5-YR Frequency of Class 1 Relief Valves Our code of record requires that any individual valve shall not exceed 5 years. Our code of record requires that any individual valve shall not exceed 5 years. Our Technical Specifications allow IST frequencies of 2 years or less to have a grace period of 1.25 times the frequency, if necessary. Our Technical Specifications allow IST frequencies of 2 years or less to have a grace period of 1.25 times the frequency, if necessary. NUREG 1482, Revision 1, section 3.1.3, states "However, licensees should not extend the test intervals for safety and relief valves defined in Appendix I to the OM Code, other than to coincide with a refueling outage….“ A preliminary look by our Licensing Department is that we will have to submit a relief request to the NRC for approval. I am looking for input from the industry on this subject.

3. 3 ISTOG QUESTIONS –2007 1.5-YR Frequency of Class 1 Relief Valves 1. Are we required to obtain NRC approval to perform the safety valve test at just over 5 years to make it to the refueling outage? 2. Has anyone invoked this NUREG 1482 position at their plant? NRC Question 1: Can the five years (or ten years) for relief valve testing as stated in the OM Code Appendix I 1998 and later be exceeded without relief? Are you allowed to exceed the five (ten) years as a result of the refueling outage frequency being changed if, the relief valve’s original schedule was within the Code interval? Would this require relief (exigent or otherwise) or just notification to the NRC?

4. 4 ISTOG QUESTIONS –2007 2. AFW Flow Instrumentation When on Miniflow NPP utilizes the 1998 ed of the ASME O&M Code with the 1999 and 2000 addenda. NPP utilizes the 1998 ed of the ASME O&M Code with the 1999 and 2000 addenda. The auxiliary feedwater pumps are run on miniflow to the condensate storage tank during quarterly IST's. The auxiliary feedwater pumps are run on miniflow to the condensate storage tank during quarterly IST's. The miniflow line has a multistage orifice to provide a fixed flow resistance and flow. Flow is assumed constant based upon the manufacturer supplied orifice flow curve and pump differential pressure is measured. Flow is assumed constant based upon the manufacturer supplied orifice flow curve and pump differential pressure is measured.

5. 5 ISTOG QUESTIONS –2007 2. AFW Flow Instrumentation When on Miniflow No permanent plant flow instrumentation was installed on the miniflow line. No permanent plant flow instrumentation was installed on the miniflow line. During the initial ten year IST interval and subsequent ten year updates, the NRC has granted relief for this lack of instrumentation. During the initial ten year IST interval and subsequent ten year updates, the NRC has granted relief for this lack of instrumentation. NPP is considering installation of flow instrumentation due to concerns about orifice blockage or erosion, pump damage if orifice should become blocked and uncertainty of future relief request approvals. NPP is considering installation of flow instrumentation due to concerns about orifice blockage or erosion, pump damage if orifice should become blocked and uncertainty of future relief request approvals. The following questions are submitted for industry peer input:

6. 6 ISTOG QUESTIONS –2007 2. AFW Flow Instrumentation When on Miniflow 1. Does your plant have instrumented flow instrumentation for auxiliary feedwater or similar pumps when on miniflow? 2. Was your plant refused relief during initial IST program submittal or subsequent updates for lack of flow instrumentation for auxiliary feedwater pumps or other IST pumps? If so, please provide approximation of when relief was requested and denied. NRC Question 2: Is relief being given for non-instrumented minimum recirc lines (as was provided in GL 89-04, position? Is relief required if, per the Code 1998 Ed and later, it appears that you do not need to FIX a parameter?

7. 7 ISTOG QUESTIONS –2007 3. AOV Issue During our refuel outage in March of this year the actuators were rebuilt and the packing adjusted (packing load was increased due to history of packing leaks) for our Reactor Recirc Pump seal cooling supply isolation valves (CV1804A an CV1804B). Post maintenance stroke time for CV1804A was 3.22 seconds and 3.19 seconds for CV1804B without system pressure which is about 1500 psi. The reference stroke time for CV1804A is 3.0 seconds and for CV0804B 3.4 seconds. Since the outage, the stroke time for both valves has increased to near their upper IST limits as follows: CV1804A CV1804B 3/8/07 3.22 3.19 5/2/07 3.84 3.85 8/2/07 4.17 4.97 CV1804A CV1804B 3/8/07 3.22 3.19 5/2/07 3.84 3.85 8/2/07 4.17 4.97

8. 8 ISTOG QUESTIONS –2007 3. AOV Issue The limiting value for full stroke is 4.5 seconds for CV1804A and 5 seconds for CV1804B, which is the same as the acceptance criteria. These are 3/4 inch category A valves with a safety function to close for primary containment isolation. Average stoke time over the past 12 years has been very close to the reference value for both valves with variation of about.+/- 0.3 seconds. Doing maintenance online is impractical due to the manual isolation valve being inside the primary containment. An LLRT, if required, would also be impractical due to the location of the isolation valve.

9. 9 ISTOG QUESTIONS –2007 3. AOV Issue We think that we can explain the increase in the first stroke time after the outage, increased packing load and system pressure. However, we are struggling with explaining the second increase in stroke time. Any insight that you could provide on the second increase in stroke time would be welcomed. We think that we can explain the increase in the first stroke time after the outage, increased packing load and system pressure. However, we are struggling with explaining the second increase in stroke time. Any insight that you could provide on the second increase in stroke time would be welcomed. Also, our AOV engineer and I&C Supervisor recommend cycling one of the valves as part of the troubleshooting. If we were to do this and the stroke time exceeds the acceptance criteria do we declare the valve inoperable? My first thought is yes. What do you all think? So, we are basically looking for options to address the issue with these two valves. Any insight that you can provide would be appreciated. NRC Question 3: Any insight that you can provide for the above?

10. 10 ISTOG QUESTIONS –2007 4. BWR's - NRC Concerns with HPCI IST Criteria NPP recently had an NRC CDBI inspection that included review of HPCI pump/turbine testing relative to design basis versus ASME based IST and NUREG-1482 requirements. NPP recently had an NRC CDBI inspection that included review of HPCI pump/turbine testing relative to design basis versus ASME based IST and NUREG-1482 requirements. The bottom line is that we needed to do more extensive instrument tolerance analysis for the inspection than was previously done, especially including speed limiter tolerance and flowmeter orifice uncertainties, to show that the IST procedure did not have LTA acceptance criteria or allow performance below the HPCI design requirements.

11. 11 ISTOG QUESTIONS –2007 4. BWR's - NRC Concerns with HPCI IST Criteria The OS trip setpoint is 5000 rpm. We have a design requirement of 5000 gpm injected at a discharge pressure of SRV setting (plus tolerance), plus discharge piping head loss. The OS trip setpoint is 5000 rpm. We have a design requirement of 5000 gpm injected at a discharge pressure of SRV setting (plus tolerance), plus discharge piping head loss. (Another "heads-up": We were also highly challenged due to the BJ DVS12x14x23 booster pump impeller change out in the middle 1980's. I am led to believe this was a common change in the industry. This left us with booster pump curves that were not certified since the casing was not sent back for testing. However, we eventually beat that issue back and it was dropped.) I don't know if our flow/speed controls are the same, but ours essentially tries to meet a flow demand by varying pump speed, subject to maximum speed being limited to 4100 rpm (nominal).

12. 12 ISTOG QUESTIONS –2007 4. BWR's - NRC Concerns with HPCI IST Criteria Back to instrument tolerances, some engineers here pointed to the fact that GE has stated numerous times that the HPCI design includes sufficient margin to cover instrument error, and so tolerances do not need to be incorporated in testing. However, this view is inconsistent with DEMONSTRATION that the design is met, and did not seem to have any merit at all with the NRC inspectors. Back to instrument tolerances, some engineers here pointed to the fact that GE has stated numerous times that the HPCI design includes sufficient margin to cover instrument error, and so tolerances do not need to be incorporated in testing. However, this view is inconsistent with DEMONSTRATION that the design is met, and did not seem to have any merit at all with the NRC inspectors. Factoring in all the instrument tolerances, and backfitting our past HPCI test results, we showed operability, but with much less margin that desired. I have an action to improve our margin before restart from RF12 in the last week of this October. I spoke with GE briefly to inquire about the feasibility of increasing the turbine speed limiter by 100 rpm or so, for a 5% discharge pressure margin gain. I was told that it might be feasible in the time frame I need if anyone else already has a higher speed. Factoring in all the instrument tolerances, and backfitting our past HPCI test results, we showed operability, but with much less margin that desired. I have an action to improve our margin before restart from RF12 in the last week of this October. I spoke with GE briefly to inquire about the feasibility of increasing the turbine speed limiter by 100 rpm or so, for a 5% discharge pressure margin gain. I was told that it might be feasible in the time frame I need if anyone else already has a higher speed.

13. 13 ISTOG QUESTIONS –2007 4. BWR's - NRC Concerns with HPCI IST Criteria I would also like to know if you think we are in left field by incorporating speed control tolerance in the analysis for maximum allowable pump degradation. (Note: we have the same issues with RCIC, but margins are better) I would also like to know if you think we are in left field by incorporating speed control tolerance in the analysis for maximum allowable pump degradation. (Note: we have the same issues with RCIC, but margins are better) NPP requests feedback on the following questions (please read the explanation text below for the context of these questions). NPP requests feedback on the following questions (please read the explanation text below for the context of these questions). What are your HPCI speed limiter and overspeed trip setpoints? Do you consider instrument tolerances, including speed controller error, in your IST acceptance criteria? For flow measurement accuracy, do you include any uncertainty for the flow element / orifice? NRC Question 4: Would the NRC consider the instrument error for instrument tolerances to include the speed controller error or, would this be covered under the IN 97-90 for “design” inclusion? Would the NRC consider the instrument error for instrument tolerances to include the speed controller error or, would this be covered under the IN 97-90 for “design” inclusion?

14. 14 ISTOG QUESTIONS –2007 5. Category A Designation for Feedwater Isolation Valves NPP requests feedback on the Comprehensive Pump Test Instrument issues: 1.For those stations who have gone to comprehensive pump testing, what has been your experience with the new +/- 0.5% pressure instrument accuracy requirements? 2.Did you use existing plant instrumentation, previously calibrated to 2%, and now calibrate it to the tighter range? 3.Do you do pre and post calibrations around the comprehensive pump test to assure the instrument is demonstrated to be within range during the test? If not, what is your calibration frequency?

15. 15 ISTOG QUESTIONS –2007 5. Category A Designation for Feedwater Isolation Valves 4.Do you have any pumps to where you have differential pressure as the set value? 5.If so, what is you experience in meeting the +/- 0.5% set range (ref. new draft NUREG 1482, Section 5.3)? 6.What is your experience with instrumentation fluctuations in trying to achieve the set value? NRC Question 5: Has the NRC given any more consideration to relaxing the upper limit for CPT of 3% by approval of a relief request? Also has the NRC given any relief approval for the use of 0.5% gages for pressure? Any examples? Also has the NRC given any relief approval for the use of 0.5% gages for pressure? Any examples?

16. 16 ISTOG QUESTIONS –2007 6. Cooling Water/Service Water Pumps 1.Do your emergency safeguards pumps run continuously or are they Cat B Pumps? 1.Do your emergency safeguards pumps run continuously or are they Cat B Pumps? 2.How many Safeguards Cooling Water pumps do you have per unit? 2.How many Safeguards Cooling Water pumps do you have per unit? 3.How often are your pumps refurbished? (overhauled/impellers replaced?) 3.How often are your pumps refurbished? (overhauled/impellers replaced?) 4.Are the pumps in a severe service environment? (e.g. a lot of sand or silt in the water?) 4.Are the pumps in a severe service environment? (e.g. a lot of sand or silt in the water?)

17. 17 ISTOG QUESTIONS –2007 6. Cooling Water/Service Water Pumps NRC Question 6: Would the NRC consider pumps that are ONLY operated (from a convenience standpoint) routinely operated pumps and require that they be classified as Group A? (Typically this involves the HPSI pumps being used to “fill” the SITs.)

18. 18 ISTOG QUESTIONS –2007 7. IST Program Question on Diesel Starting Air Skid Check Valves During a replacement of the starting air pressure control valves (PCVs) that reduce pressure from 250 psig to 125 psig for use in the starting and over-speed interlocks on our emergency diesel generator 4, both the right and left bank PCVs were found installed backwards. These are ball type check valves associated with the PCVs which are utilized to bleed back pressure to the inlet of the PCVs and back to the air header. The right bank check valve was found installed backwards as well. Further investigation found that this condition has been this way since first installed.

19. 19 ISTOG QUESTIONS –2007 7. IST Program Question on Diesel Starting Air Skid Check Valves This led the NRC to question, why this condition was not found before? Are these check valves in the IST program and if not, should they be? Are these check valves in the IST program and if not, should they be? I am aware that NPP and NPP are the only plants with the same manufactured type diesel system, Nordberg, but I am hoping that others may have diesels with pneumatic starting air systems with these PCVs and check valves on a skid. I am aware that NPP and NPP are the only plants with the same manufactured type diesel system, Nordberg, but I am hoping that others may have diesels with pneumatic starting air systems with these PCVs and check valves on a skid. Hence my question, Do you have these check valves in your IST program? If not, how did you justify exclusion? If so, are they in your augmented program? NRC Question 7: Would these check valves be required to be in the IST Program?

20. 20 ISTOG QUESTIONS –2007 8. Drywell Purge and Vent Valves NPP has 24in M.O. butterfly valves as Inbd Cont Isol valves on our Drywell N2 Purge and Vent penetrations. Our Tech Specs require LLRT every 6 months and/or within 92 days following a valve stroke. These are normally closed valves, safety function to remain closed, stroke time tested only during Cold S/D. Our Drywell is maintained N2 inerted during operation. Operators would only open them by choice during post accident recovery phase. For many years NPP has tested these valves online every 6 months AND every RFO.

21. 21 ISTOG QUESTIONS –2007 8. Drywell Purge and Vent Valves We are considering a change to testing only online every 6 months and would appreciate responses to the following questions for your equivalent valves: 1.Do you perform online LLRT of these valves? If so, do you also perform scheduled LLRTs during RFOs? 2.Have you made (or considered making) a change to LLRT schedule similar to what we are planning? 3.How often do you stroke test these valves? 4.Do you utilize a CSJ for these stroke tests? NRC Question 8: Would the NRC consider the justification for testing these valves at CSJ to be acceptable?

22. 22 ISTOG QUESTIONS –2007 9. Experience Stopping Packing Leak without Performing PMT We have an MOV that is stroke time tested closed at a cold shutdown frequency that has developed a packing leak while in the open position (online). In our case, electrically, the valve would be 8% off of the backseat. The valve would be taken to manual and fully opened. backseat. The valve would be taken to manual and fully opened. The affect on the closing stroke time would be estimated and it would be well within the design basis stroke time.

23. 23 ISTOG QUESTIONS –2007 9. Experience Stopping Packing Leak without Performing PMT Alternatively, an option may be to tighten packing nuts to a torque value that was previously obtained from a past work order, which would give a basis that the valve should stroke in a similar time. Has anyone justified taking a valve manually to the backseat to attempt to stop a packing leak without performing a post- maintenance stroke time test? NRC Question 9: Would the NRC consider this an acceptable practice?

24. 24 ISTOG QUESTIONS –2007 10. Failed Valve Stroke Time At NPP we have an air operated valve that was repacked in Feb 2007 during our last RFO. The valve was stroked closed in 3.13 sec during post maintenance testing (reference value is 2.87 sec). During the next quarterly test the valve initially stroked in 4.5 sec which is outside the upper acceptance criteria of 4.3 second (this valve does not have a limiting value). The valve stroked a second time in 3.14 seconds. ISTC-5115 states that we can accept the second stroke time providing we can explain the initial deviation. However, no such explanation is revealing itself.

25. 25 ISTOG QUESTIONS –2007 10. Failed Valve Stroke Time This valve is normally open during the quarterly test and stroked closed and timed and then reopened. During this most recent test the valve was closed and de-energized because its partner isolation valve had also failed its stroke time (a whole other story). The valve was re-energized opened and then timed closed which is when it failed its stroke time. 1.Any suggestions on resolving this situation? 2.Also what criteria do you use for when to re-baseline valve stroke times? NRC Question 10: Is it the NRC’s position that ALL power operated valves in the IST Program require that a Limiting Value of Full Stroke Time be established?

26. 26 ISTOG QUESTIONS –2007 11. IST Instrumentation Questions pertaining to use of permanent plant instruments: For the dozen or so of these instruments we use for IST we have an existing evaluation that lists the instrument accuracy. For instance, one flow instrument is listed with an accuracy of +/- 1% (flow transmitter feeding analog flow indicator in the control room). When I look closely at it's instrument calibration spec sheets there is an allowed as found tolerance band of 0.95% at full scale ( 100% scale is 9150 GPM and cal tolerance range is 9063 - 9237). However, our typical IST measurement is around 6200 GPM. At the calibration cardinal point of 6000 GPM the cal tolerance range is 5868-6132, or +/- 2.2%.

27. 27 ISTOG QUESTIONS –2007 11. IST Instrumentation The actual loop accuracy is not linear down from 100% scale, it is logarithmic. At the lowest cardinal point of 2000 GPM the acceptable readings are 1634-2366, or +/- 18.3%. I have been given to understand that this is industry standard calibration methodology and that accuracy of better than 2% of full scale is what the Code requires - not accuracy of +/- 2% of reading. The Code does say that 2% of full scale is acceptable for individual analog instruments.

28. 28 ISTOG QUESTIONS –2007 11. IST Instrumentation 1.Does this type of flow instrument described above classify as an "individual analog instrument"? 2.For combinations of instruments (loop accuracy) is the Code criteria applicable as 2% of full scale or 2% of reading? NRC Question 11: How does the NRC determine if an instrument is analog or digital? Is it based on the “output” device (i.e. if the gage or meter is analog, then the instrument is analog)?

29. 29 ISTOG QUESTIONS –2007 11. IST Instrumentation NRC Question 11: Is it based on the “input” device (i.e. if the transmitter is digital then the instrument is digital)? If a suction and discharge pressure gages are used to determine the differential pressure of a pump, do we need to add the inaccuracies of each of the gages together using the Square Root Sum of the Squares (SRSS) method or, can we just consider the individual instruments solely on the bases of each instrument satisfying the Code instrument tolerance requirements of +/- 2%? If you use multiple flow instruments to determine the “total” flow, do you need to use the SRSS method to determine total instrument inaccuracy?

30. 30 ISTOG QUESTIONS –2007 12. Mode Change Checklist Question I am interested in how other plants make sure that all required IST tests have been performed when the plant is getting ready to change modes at the end of an outage. At NPP, each department has a mode change checklist listing requirements that have to be completed before going from Mode 5 to Mode 4, Mode 4 to Mode 3, etc. At NPP, each department has a mode change checklist listing requirements that have to be completed before going from Mode 5 to Mode 4, Mode 4 to Mode 3, etc. The STA keeps the master checklist. After each department completes their checklist for the applicable mode change, they sign the master checklist. The STA keeps the master checklist. After each department completes their checklist for the applicable mode change, they sign the master checklist. We do not change modes until the master checklist is complete for that mode change.

31. 31 ISTOG QUESTIONS –2007 12. Mode Change Checklist Question 1. Do you use a checklist or some other tool to verify that all required IST tests have been performed before changing modes? modes? 2. If you use a checklist, what do you do with the checklist when it is complete? Throw it away, file it, archive it as a QA record, etc? record, etc? NRC Question 12: Any comments to the above? Any comments to the above?

32. 32 ISTOG QUESTIONS –2007 13. MOV Stroke Time Testing NPP Technical Specification 3.3.5.4 requires verifying that ESF Response Time is within limits. For power-operated valves, the ESF Response Time ends when the valve travels "to its required position". NPP Technical Specification 3.3.5.4 requires verifying that ESF Response Time is within limits. For power-operated valves, the ESF Response Time ends when the valve travels "to its required position". When calculating ESF Response Time, we use IST stroke times for the valve stroke portion. No allowance is made for the valve position indication limit switch setting tolerance (0-10% of stroke). If you stroke time your safety related MOVs in the closed direction using a stopwatch that is stopped when the red indicating light goes out, does your stroke time acceptance criteria take into account that the red light limit switch is set in a 10% of band from the full closed position? Or is the red light turning off considered to indicate that the MOV is fully closed? NRC Question 13: As asked above? Also, is it the NRC position that position indication verification of a power operated valve be performed in “both” positions, regardless of the safety function of the valve?

33. 33 ISTOG QUESTIONS –2007 14. NIC Query NPP has experienced through-body leakage on (3) saltwater pump discharge nozzle check valves when operating at normal system flow and pressure. NPP is attempting to determine if similar valve failures of this nature have occurred in the industry. Any information you can provide regarding the questions listed below would be greatly appreciated: 1. Does your facility have these make & model nozzle check valves in service and if so, in what application?

34. 34 ISTOG QUESTIONS –2007 14. NIC Query 2. Have you experienced through-body leakage with these valves? 3. Have you identified the presence of casting defects or crevice corrosion with these valves? Make --Enertech Make --Enertech Model --DRV-B Model --DRV-B Size -- 24" Size -- 24" System Application --check valve for saltwater pump System Application --check valve for saltwater pump Service Condition --saltwater @ 35psi Service Condition --saltwater @ 35psi NRC Question 14: Any comments on above? Any comments on above?

35. 35 ISTOG QUESTIONS –2007 15. Observations of Surveillance Tests (IST's) At NPP, there recently has been a question relative to involvement of the Engineering staff in observation of IST's. Pump IST's are performed by Operations Test Group and test results are forwarded to the pump engineers for review and approval. Generally, the pump engineers do not witness the tests unless there are unusual circumstances. Generally, the pump engineers do not witness the tests unless there are unusual circumstances. Each pump test is reviewed by a pump engineer and the group supervisor.

36. 36 ISTOG QUESTIONS –2007 15. Observations of Surveillance Tests (IST's) Valve IST's are performed by Operations including final review and acceptance of test results. Corrective Actions are initiated when acceptance criteria is not met. 15. Observations of Surveillance Tests (IST's) Valve IST's are performed by Operations including final review and acceptance of test results. Corrective Actions are initiated when acceptance criteria is not met. Valve engineers periodically review trend data, but do not participate in or observe valve IST's unless there is an abnormal situation. 1. Does your plant have a separate group who performs the pump test vs. the actual pump engineer?

37. 37 ISTOG QUESTIONS –2007 15. Observations of Surveillance Tests (IST's) 2.If you have a separate group that performs the pump tests, does the pump engineer(s) additionally observe the pump tests during performance? 3.Does your plant have valve tests performed by personnel other than engineering? 4. If so, does engineering additionally observe performance of valve testing? NRC Question 15: Any comments on above?

38. 38 ISTOG QUESTIONS –2007 16. OMN-1 (ISTC App. III) Reconciliation As you know there has been heated debate about the 2 versus 3 risk ranking issue. I would like to offer a fresh perspective and get some feedback about whether a Code inquiry is appropriate or even necessary. It seems to me that the main concern from the Code committee perspective, as it pertains to use of 2 risk categories, is the scheduling frequency of the MOV exercise testing (EXER). As you know there has been heated debate about the 2 versus 3 risk ranking issue. I would like to offer a fresh perspective and get some feedback about whether a Code inquiry is appropriate or even necessary. It seems to me that the main concern from the Code committee perspective, as it pertains to use of 2 risk categories, is the scheduling frequency of the MOV exercise testing (EXER). The main concern from the MOV Program owners (MUG) perspective, as it pertains to continued use of the 3 risk categories, is the scheduling of GL 96-05 tests (which would now be considered Inservice Test – (IST).

39. 39 ISTOG QUESTIONS –2007 16. OMN-1 (ISTC App. III) Reconciliation What IF - plants took their existing 3 tier MOV risk classifications and lumped ALL High and Med MOVs into the HSSC category and all their Low MOVs into the LSSC category and used this "new" list for the purpose of creating / scheduling the exercise test. However, for the purposes of setting test intervals for their GL 96-05 tests they would still use the existing JOG matrix with their base 3 tier Risk and Margin classifications. However, for the purposes of setting test intervals for their GL 96-05 tests they would still use the existing JOG matrix with their base 3 tier Risk and Margin classifications. In the latest version of ISTC App. III Section 3300 and 3310 there is NO specific discussion of the IST interval relative to HSSC.

40. 40 ISTOG QUESTIONS –2007 16. OMN-1 (ISTC App. III) Reconciliation Sect 6440 (Determination of Test Interval) also has NO specific discussion of the IST interval relative to HSSC. Only in Sect III 3722 - LSSC MOVs is there any sort of tie-in between Risk categorization and IST interval. However, 3722 (c) allows for IST intervals for LSSC to be extended beyond 5Y given a mature program with solid historical data (i.e., typical GL 96-05 Program). 3722 (d) stipulates a MAX IST interval of 10Y for LSSC's, but that is consistent with JOG max interval anyway.

41. 41 ISTOG QUESTIONS –2007 16. OMN-1 (ISTC App. III) Reconciliation So in a nutshell - As long as plants set their exercise testing intervals based on the 2 tier HSSC and LSSC classifications (would be HSSC = JOG H and M and LSSC = JOG L) they would meet the intent of the Code. I don't think anyone has issues with doing that. The wording in App. III does NOT seem to directly impact how current GL 96-05 test (IST) intervals are determined (could continue using the JOG matrix). I don't think anyone has issues with doing that. The wording in App. III does NOT seem to directly impact how current GL 96-05 test (IST) intervals are determined (could continue using the JOG matrix). NRC Question 16: NRC Question 16: Does the NRC accept the “2 tier” method of risk ranking in accordance with OMN-1 as well as the “3 tier” method? In other words, can you use the 2 tier method to rank MOVs for diagnostic testing frequency and then use the 3 tier method to determine exercise frequency or, vice a versa?

42. 42 ISTOG QUESTIONS –2007 16. OMN-1 (ISTC App. III) Reconciliation NRC Question 16 (continued): Is it permissible to extend the frequency of the valve position indication to the diagnostic frequency of the MOVs when implementing OMN-1 CC? The CC is silent on ALL sections of the Code with the exception of the Leak section. It appears that the Code has “included” the valve position indication verification within the CC. Comments?

43. 43 ISTOG QUESTIONS –2007 17. PIV Testing In today's world of performance based testing, risk based testing, etc., I thought it was time to bring up Pressure Isolation Valve (PIV) testing, once again. In today's world of performance based testing, risk based testing, etc., I thought it was time to bring up Pressure Isolation Valve (PIV) testing, once again. At NPP, we currently perform PIV testing on Core Spray and RHR lines every refueling outage, utilizing a hydro pump test skid and high pressure hoses. At NPP, we currently perform PIV testing on Core Spray and RHR lines every refueling outage, utilizing a hydro pump test skid and high pressure hoses. We have had 10+ years of successful tests (need to validate) and pick up significant dose each outage performing this testing. Appendix J air tests are performed on the same valves. We have had 10+ years of successful tests (need to validate) and pick up significant dose each outage performing this testing. Appendix J air tests are performed on the same valves.

44. 44 ISTOG QUESTIONS –2007 17. PIV Testing Therefore, I have the following questions: 1. Has any plant successfully extended the frequency of a PIV test or eliminated a PIV test via a relief request? 2. What is your method of testing PIVs? NRC Question 17: Is it permissible to use the LLRT method of testing valves by using air as a substitute for using water? (This has been an ongoing discussion and at last we heard this was NOT an acceptable method.) Can you provide further clarification or guidance?

45. 45 ISTOG QUESTIONS –2007 18. Preconditioning Question At NPP we isolated a section of Internal Containment Spray system piping using a tag out or clearance that included two IST program valves as boundary isolations. The piping was isolated to perform corrective maintenance for a flange boric acid leak. Several hours later following completion of the corrective maintenance, the scheduled quarterly Internal Containment Spray test was performed and was also used as a post maintenance test to leak check the flange repair. Several hours later following completion of the corrective maintenance, the scheduled quarterly Internal Containment Spray test was performed and was also used as a post maintenance test to leak check the flange repair. The valves that were used as tag out boundaries were stroke time tested during the surveillance. The stroke times were consistent with stroke times for the previous two years of testing.

46. 46 ISTOG QUESTIONS –2007 18. Preconditioning Question Our NRC resident is proposing a violation stating the valves were unacceptably preconditioned. Our NRC resident is proposing a violation stating the valves were unacceptably preconditioned. The violation would be an appendix B procedure violation based upon the statement in NUREG 1482, Rev. 1, page 3-21 that says: “...the staff considers unacceptable preconditioning in the IST program to... (2) operation of a pump or valve shortly before a test, if such operation could have been avoided through plant procedures with personnel and plant safety maintained..." The violation would be an appendix B procedure violation based upon the statement in NUREG 1482, Rev. 1, page 3-21 that says: “...the staff considers unacceptable preconditioning in the IST program to include... (2) operation of a pump or valve shortly before a test, if such operation could have been avoided through plant procedures with personnel and plant safety maintained..."

47. 47 ISTOG QUESTIONS –2007 18. Preconditioning Question Please provide feedback on the following questions: 1. Does your tagout/clearance procedure require as found stroke time testing of IST valves used as boundaries when hanging/clearing tags? 2. If you identify a case of inadvertently stroking a valve prior to performing the inservice test how do you answer the NRC Inspection Manual Part 9900 technical guidance question “Does the practice bypass or mask the as found condition of the pump or valve?”

48. 48 ISTOG QUESTIONS –2007 18. Preconditioning Question 3. What length of time do you consider as the minimum to satisfy the NUREG 1482, Rev. 1, statement on page 3-21 of “shortly before”? NRC Question 18: Your thoughts on the above and, in general, “preconditioning”. (In my opinion, unacceptable preconditioning is that activity (whether deliberate or accidental), which interferes or affects the ability of a facility to be able to detect or monitor for degradation. Acceptable would be pretty much the opposite.) (In my opinion, unacceptable preconditioning is that activity (whether deliberate or accidental), which interferes or affects the ability of a facility to be able to detect or monitor for degradation. Acceptable would be pretty much the opposite.)

49. 49 ISTOG QUESTIONS –2007 19. Pre-service IST Requirements We may be installing 4 check valves which will be included in our IST Check Valve Disassembly and Inspection Program. I would like to get some feedback on what you feel would be the appropriate IST pre-service test for check valves that will be included a D&I program, since it is not feasible to test the valves with flow with flow I would like to get some feedback on what you feel would be the appropriate IST pre-service test for check valves that will be included a D&I program, since it is not feasible to test the valves with flow with flow NRC Question 19: Comments? Comments?

50. 50 ISTOG QUESTIONS –2007 20. Pressurizer PORV Testing In our Tech Specs we have the following surveillance requirement for Pressurizer PORVs: Every 18 months: Verify the nitrogen supply for each PORV is OPERABLE by: a. Manually transferring motive power from the air supply to the nitrogen supply, b. Isolating and venting the air supply, and c. Operating the PORV through one complete cycle.

51. 51 ISTOG QUESTIONS –2007 20. Pressurizer PORV Testing Question: If you have a similar surveillance requirement when is it performed? a. Prior to or during shutdown for a refueling outage, or b. Sometime during the refueling outage. a. Prior to or during shutdown for a refueling outage, or b. Sometime during the refueling outage. NRC Question 20: Comments? Comments?

52. 52 ISTOG QUESTIONS –2007 21. PIV Leak Testing I would greatly appreciate answers to the following questions that could assist me with development of a Pressure Isolation Valve (PIV) leak test designed to fully comply with the requirements of OM-10, 4.4.4.3 and/or ISTC-3630, depending on the specific Code edition a plant is on. My proposed test would use air as the test medium instead of water which is the case with traditional PIV seat leakage tests. 1. Has any plant implemented the guidance of OM-10 paragraph 4.2.2.3 or likewise ISTC-3630 for PIV's where air was used as the test medium in lieu of a traditional water test?

53. 53 ISTOG QUESTIONS –2007 21. PIV Leak Testing 2. If so, is your permissible leakage rate established by your own calculation and acceptance criteria or simply based upon the Code provided formula of (7.5) (D) standard cubic feet/day formula? 3.If Owner established, would you be willing to share the basis of your calculation? 3.If Owner established, would you be willing to share the basis of your calculation? NRC Question 21: Is it permissible to use the LLRT method of testing valves by using air as a substitute for using water? (This has been an ongoing discussion and at last we heard this was NOT an acceptable method.) Is it permissible to use the LLRT method of testing valves by using air as a substitute for using water? (This has been an ongoing discussion and at last we heard this was NOT an acceptable method.) Can you provide further clarification or guidance?

54. 54 ISTOG QUESTIONS –2007 22. CPT Plant Modifications NPP Station will be committed to the ASME Code requirement to perform Comprehensive Pump Testing (CPT) as part of transitioning from the current 4th to 5th 10 year interval IST program which becomes effective on 1/1/10. The only program pumps that can not be tested at or above accident mitigation flow, NPP's definition of pump "design flow rate", are the two Containment Spray pumps. These pumps are currently tested each quarter at a maximum attainable (using all available and measurable parallel flow paths) reference flow rate of 270 gpm. The accident mitigation flow rate for a Containment Spray pump is 1300 gpm.

55. 55 ISTOG QUESTIONS –2007 22. CPT Plant Modifications To ensure an optimum technical and cost effective solution to this problem, NPP is seeking peer operational experience relative to successful system piping modifications (temporary or permanent in nature), additional test strategies (including cases where NRC relief requests were submitted and granted) or other types of compensatory measures taken which resulted in being able to successfully perform a CPT within +/- 20 % of pump design flow (ISTB-3300, Reference Values). NRC Question 22: Any more thoughts regarding the “design flow” and what would constitute acceptable alternative or a hardship?

56. 56 ISTOG QUESTIONS –2007 23. Relief to Use Tank Level Change over Time for Flow Rate At NPP, we have vertical centrifugal Fuel Oil Transfer Pumps mounted over our Emergency Diesel Generator Fuel Oil Storage Tanks. We do not have flow indicators in the lines from the Storage Tanks to the Day Tanks, so we currently measure flow using a Day Tank level change over time. We currently have a relief request approved to do this, and are presently updating to the 2001 Edition of the ASME OM Code. During review of this relief request for the next 10-year interval, the NRC stated that relief is not able to be granted because NUREG-1482, Rev.1, Section 5.5.2 only applies to positive displacement pumps and we have vertical centrifugal pumps, unless we can explain why this is OK for a centrifugal pump as well.

57. 57 ISTOG QUESTIONS –2007 23. Relief to Use Tank Level Change over Time for Flow Rate 1. If you have centrifugal FO Transfer Pumps, do you use a change in Day Tank level over time to determine the flow rate? 2. If so, do you have a copy of a relief request that I could use? OR do you use some other method to measure flow rate? NRC Question 23: Is this an acceptable method? This appears to be allowed per the Code ISTB? Code ISTB? Does the NRC consider Diesel Fuel Oil Transfer Pumps to be “skid mounted”?

58. 58 ISTOG QUESTIONS –2007 23. Relief to Use Tank Level Change over Time for Flow Rate NRC Question 23 (con’t): General guidance is that if a component CANNOT be tested using the IST requirements in the Code (impractical), and the component is tested (justified to be tested adequately) when the primary component is run, then it can be considered “skid-mounted”. However, typically DG FOTPs are ABLE to be tested using IST requirements and are NOT run every time the DG is operated. Would these be “skid-mounted”? What is the NRC bottom line position?

59. 59 ISTOG QUESTIONS –2007 24. Review of US PWR Pressurizer Spring Loaded Safety Relief Valve Test Procedures, February 2004 We currently carry out Trevi-testing of its Pressurizer Safety Relief Valves immediately after plant shutdown for each refueling outage (every 18 months). This is on critical path and requires purging of the Pressurizer Relief Tank to remove gaseous radwaste. We are interested in rescheduling the testing and would like responses to the following questions: 1.At what time in the cycle/outage do you test your PZR SRVs? 2. How often do you test your PZR SRVs?

60. 60 ISTOG QUESTIONS –2007 24. Review of US PWR Pressurizer Spring Loaded Safety Relief Valve Test Procedures, February 2004 3. Have you ever suffered failure of a PZR SRV to reseat? If so, when and what action was taken? 3. Have you ever suffered failure of a PZR SRV to reseat? If so, when and what action was taken? 4. Have you considered rescheduling of PZR SRV testing? If so, what was the result? 4. Have you considered rescheduling of PZR SRV testing? If so, what was the result? We are working on cooling down and borating in parallel, this hold will obviously stop the benefit of this initiative. NRC Question 24: Any comments or guidance regarding “trevitesting” or other insitu methods? Any comments or guidance regarding “trevitesting” or other insitu methods?

61. 61 ISTOG QUESTIONS –2007 25. Temporary Pressure Gauges For those of you who have or are moving to a later Edition of the Code that requires comprehensive pump testing, I am looking for input on how you plan on handling your requirements for higher accuracy pressure instrumentation. 1. Does your permanently installed pressure instrumentation meet the accuracy requirements of +/-0.5% of full scale (analog) or over the calibrated range (digital)? 2. If the above answer is no for some or all, what do you plan on doing for your comprehensive pump testing (i.e. install temporary gauges or make permanent instrumentation changes)? What is the basis for your decision?

62. 62 ISTOG QUESTIONS –2007 25. Temporary Pressure Gauges 3. If answer #1 is yes, what type of gauges do you use and what is the calibration frequency of your gauges? 3.1 Do you have concerns with the higher accuracy gauges staying within calibration? 3.2 Is the +3% upper operability limit a concern? NRC Question 25: Any comments on above?

63. 63 ISTOG QUESTIONS –2007 26. Testing During Power Ascension NUREG-1482, Rev. 1, Guidelines for Inservice Testing at Nuclear Power Plants, section 3.1.1.2, “Testing at a Refueling Outage Frequency for Valves Tested During Power Ascension”, provides guidance on the testing of valves that can only be tested during power ascension or at power for valves that have deferred test justifications. NUREG-1482, Rev. 1, Guidelines for Inservice Testing at Nuclear Power Plants, section 3.1.1.2, “Testing at a Refueling Outage Frequency for Valves Tested During Power Ascension”, provides guidance on the testing of valves that can only be tested during power ascension or at power for valves that have deferred test justifications. This guidance identifies that for valves that can only be tested during power ascension or at power the licensees may test valves designated as “refueling” or “cold” shutdown frequency tests during power ascension or at power following an outage without the need for requesting relief.

64. 64 ISTOG QUESTIONS –2007 26. Testing During Power Ascension Have you applied this guidance to valves tested on a quarterly frequency and if so how was this documented/justified? Have you applied this guidance to valves tested on a quarterly frequency and if so how was this documented/justified? NRC Question 26: Does the NRC have any requirements or guidance on when (during RFOs or CSJs) that the component should be tested and, can the frequency be changed from Quarterly to CSJ as a result of maintenance? Does the NRC have any requirements or guidance on when (during RFOs or CSJs) that the component should be tested and, can the frequency be changed from Quarterly to CSJ as a result of maintenance?

65. 65 ISTOG QUESTIONS –2007 26. Testing During Power Ascension Clarification: Clarification: I have received some feedback on my question and I apologize for the confusion I may have caused. I have received some feedback on my question and I apologize for the confusion I may have caused. To be more specific about my situation is we are in an unplanned cold shutdown and the surveillance interval grace period for some turbine driven AFW train check valve tests may expire. To be more specific about my situation is we are in an unplanned cold shutdown and the surveillance interval grace period for some turbine driven AFW train check valve tests may expire. ISTB has an allowance for not performing the pump test in this situation but there is no similar guidance in ISTC. I was wondering if any of you have encountered a similar situation.

66. 66 ISTOG QUESTIONS –2007 26. Testing During Power Ascension Exercising Testing of RCIC/HPCI Pump Discharge Check Valves What testing methods do other BWRs employ satisfy the exerciser test in the closed direction for their RCIC and/or HPCI discharge check valves? NRC Question 26: Any additional comments? Any additional comments?

67. 67 ISTOG QUESTIONS –2007 27. Timing of Rapid Closure Valves 98 Edition of O&M Code w/ 99 & 2000 addenda CE PWR At NPP we have certain containment isolation solenoid valves which have a 1 sec MAXIMUM stroke time per our Licensee Controlled Specification (LCS). Relative to these valves: 1. Do you have valves within your IST program which are required to stroke faster than 2 seconds per your Tech Specs or LCS? 1. Do you have valves within your IST program which are required to stroke faster than 2 seconds per your Tech Specs or LCS? 2. If so, how do you time them? (what timing mechanism do you use, stop watch, chart recorder, etc,) 2. If so, how do you time them? (what timing mechanism do you use, stop watch, chart recorder, etc,) NRC Question 27: Any additional comments? Any additional comments?

68. 68 ISTOG QUESTIONS –2007 28. IST Question on Trip Valve Testing During a recent inspection NPP’s methodology for testing its Turbine Driven Auxiliary Feedwater Pumps and associated valves was questioned. During a recent inspection NPP’s methodology for testing its Turbine Driven Auxiliary Feedwater Pumps and associated valves was questioned. The concern was that we are unacceptably pre-conditioning our Overspeed Trip Valve. At NPP our Overspeed Trip Valve is Motor Operated to allow re-latching and opening the valve from the control room. The concern was that we are unacceptably pre-conditioning our Overspeed Trip Valve. At NPP our Overspeed Trip Valve is Motor Operated to allow re-latching and opening the valve from the control room. The current testing sequence is: Manually trip the Overspeed Trip Valve locally at the pump. This is done first to ensure that should we get an auto pump start while stroke timing the pump discharge/throttle MOVs the pump would not be damage as a result of run out. Manually trip the Overspeed Trip Valve locally at the pump. This is done first to ensure that should we get an auto pump start while stroke timing the pump discharge/throttle MOVs the pump would not be damage as a result of run out.

69. 69 ISTOG QUESTIONS –2007 28. IST Question on Trip Valve Testing With the Overspeed Trip Valve tripped the two discharge MOVs are stroked timed both open and closed. The MOVs are then placed in their proper throttle position. With the Overspeed Trip Valve tripped the two discharge MOVs are stroked timed both open and closed. The MOVs are then placed in their proper throttle position. The pump mini-recirc control valve is stroke timed both open and shut. The pump mini-recirc control valve is stroke timed both open and shut. The Overspeed Trip Valve motor operator is then shut (and timed) to re-latch the valve. The Overspeed Trip Valve motor operator is then shut (and timed) to re-latch the valve. The Overspeed Trip Valve motor operator is then opened (and timed) to place the pump in a ready condition. The Overspeed Trip Valve motor operator is then opened (and timed) to place the pump in a ready condition.

70. 70 ISTOG QUESTIONS –2007 28. IST Question on Trip Valve Testing The pump is started by opening (and timing) the steam inlet MOVs and the pump is tested. The pump is started by opening (and timing) the steam inlet MOVs and the pump is tested. The concern was raised that by tripping and resetting the Overspeed Trip Valve before running the pump we could be masking a condition where the valve would trip on a pump start. 1. When testing your turbine driven pumps do you first trip the overspeed trip valve? Would you consider this practice unacceptable pre-conditioning? 1. When testing your turbine driven pumps do you first trip the overspeed trip valve? Would you consider this practice unacceptable pre-conditioning? 2. If not, do you isolate steam the turbine well stroke timing the pump’s discharge throttle valves?

71. 71 ISTOG QUESTIONS –2007 28. IST Question on Trip Valve Testing NRC Question 28: Would the NRC consider this Unacceptable Preconditioning? NRC SSEI Response to Item No. 180 Question: Procedure 3808.01, step 8.2, directs operations personnel to check the overspeed trip linkage by manually tripping the overspeed trip linkage. This step is a commitment in response to RICSIL 037. RICSIL 037 states that the check should be performed following each surveillance test, however, you perform the check prior to performing a surveillance. Is this pre-conditioning? If not, why not?

72. 72 ISTOG QUESTIONS –2007 29. IST Question On Turbine Driven Pumps During Inservice Testing of NPP’s Turbine Driven Auxiliary Feedwater Pumps both turbine and pump bearing temperatures are record in addition to the ASME OM Code (95E/96A) required parameters of flow rate, differential pressure, pump speed and pump vibration. Turbine bearing vibration is also recorded but IST acceptance criteria is not applied. The pumps are run on recirculation at a flow rate of about 120 gpm for about a half hour, and then flow is set to 400 gpm (the IST flow rate). After a two minute stabilization period the IST data is collected and pump and turbine bearing temperatures are recorded. Turbine bearing vibration is also recorded but IST acceptance criteria is not applied. The pumps are run on recirculation at a flow rate of about 120 gpm for about a half hour, and then flow is set to 400 gpm (the IST flow rate). After a two minute stabilization period the IST data is collected and pump and turbine bearing temperatures are recorded.

73. 73 ISTOG QUESTIONS –2007 29. IST Question On Turbine Driven Pumps We have discovered that the bearing temperatures are not necessarily stabilized at the time they are normally recorded (after approximately 35 minutes). We have discovered that the bearing temperatures are not necessarily stabilized at the time they are normally recorded (after approximately 35 minutes). During an extended pump run this week the outboard turbine bearing temperature was taken a second time after about two hour running at 400 gpm. The temperature was found to be significantly higher than when originally recorded after 35 minutes. During an extended pump run this week the outboard turbine bearing temperature was taken a second time after about two hour running at 400 gpm. The temperature was found to be significantly higher than when originally recorded after 35 minutes. NPP request that you answer the following questions related to this issue: 1. Do you routinely monitor bearing temperatures on your turbine driven pumps (turbine and pump bearings)?

74. 74 ISTOG QUESTIONS –2007 29. IST Question On Turbine Driven Pumps 2. If question 1 is yes, do you monitor these temperatures under you Inservice Testing Program implementing procedures? 3. If question 1 is yes, what type of stabilization criteria do you use (a set time, a set change in temperature over a given time period, or other). 4. Do you assign acceptance criteria to these temperature readings that if exceeded require the pump to be declared OOS? NRC Question 29: Any comments to the above? Any comments to the above?

75. 75 ISTOG QUESTIONS –2007 30. Use of Calibrated Gauges ASME OM 1998 Code, 2000 Addendum. When performing a check valve test in the CLOSED direction by observing a gross dP across the check valve, does the gauge used for this test need to be calibrated? I believe it does per 10CFR50 App B and ISTC-3800 ‘Instrumentation’ even through we are looking for a gross dP. I don’t see any leeway in the Code, though common sense would say it wouldn’t matter. I believe it does per 10CFR50 App B and ISTC-3800 ‘Instrumentation’ even through we are looking for a gross dP. I don’t see any leeway in the Code, though common sense would say it wouldn’t matter. NRC Question 30: In general, what is the NRC’s position on when a valve is a Category A valve and when is a valve just a Category B or C valve? Specific Leakage range? Safety function? System leakage? Radiological concern? In general, what is the NRC’s position on when a valve is a Category A valve and when is a valve just a Category B or C valve? Specific Leakage range? Safety function? System leakage? Radiological concern?

76. 76 ISTOG QUESTIONS –2007 31. Valve Testing Questions Two questions on how we are testing certain types of valves have been asked at my plant and I would like input from other plants on what you are currently doing to test these valves: Two questions on how we are testing certain types of valves have been asked at my plant and I would like input from other plants on what you are currently doing to test these valves: 1. Rapid Acting Valves - NPP currently use stroke time testing (using a stopwatch, measuring the time the valve opens to it when it closes by watching the indicator lights off the control board) to prove operability and to trend for degradation (we established a reference value of 1 second which is not required by the code for trending). There are concerns (from my operations group) that this may not be an accurate representation of the actual time the valve strokes. What type of testing are you performing for rapid acting valves that satisfies the code?

77. 77 ISTOG QUESTIONS –2007 31. Valve Testing Questions Clarification for question #1 The reference value of 1 second (we use here at NPP) is for trending purposes ( the code leaves it up to the owner on how to trend for degradation but does give option of use of diagnostic equipment). My question pertains to how do you trend for degradation for rapid acting valves, if you do at all.

78. 78 ISTOG QUESTIONS –2007 31. Valve Testing Questions 2. I have been requested to evaluate the frequency of testing our Core Spray and Residual Heat Remove injection valves. Currently, we test these valves quarterly. We are experiencing frequent rising system pressures and the belief is that this condition is cause by the wear of these valves due to frequent cycling of this valve for IST testing. We are experiencing frequent rising system pressures and the belief is that this condition is cause by the wear of these valves due to frequent cycling of this valve for IST testing. a. On what frequency are you testing these valves? b. What was your justification if deferred to a cold shutdown or refueling outage? refueling outage? NRC Question 31: What is the NRC’s position regarding the above response? Is it What is the NRC’s position regarding the above response? Is it acceptable to time as stated above? acceptable to time as stated above?

79. 79 ISTOG QUESTIONS –2007 32. Operable but Degraded Question I have a question coming from our Nuclear Oversite people asking the IST Program Owner, “Should the IST Program direct Operations to consider a valve that times outside the reference range (but less than its Limiting Stroke Time) as ‘Operable but Degraded’?” 1. Do other plants do ‘Operability Assessments’ for all valves that time outside the reference range (but <LST)? Is the valve considered fully Operable as long as it is less than the LST? 2. Is the purpose of the 96 hour evaluation meant to be considered an Operability assessment? 2. Is the purpose of the 96 hour evaluation meant to be considered an Operability assessment?

80. 80 ISTOG QUESTIONS –2007 32. Operable but Degraded Question 3.If YES to #2, do other plants use the plant guidance for Operability Determinations when performing the 96 hour eval? NRC Question 32: Any comments on the above? Any comments on the above?

81. 81 ISTOG QUESTIONS –2007 NRC Question 33: What is the NRC’s position regarding testing of PORVs that are used for LTOP? What is the NRC’s position regarding testing of PORVs that are used for LTOP? For example, can you perform ONLY an exercise test on the PORV and NOT be required to perform a Stroke Time, Valve Position Indication, and Fail Safe tests? For example, can you perform ONLY an exercise test on the PORV and NOT be required to perform a Stroke Time, Valve Position Indication, and Fail Safe tests? NRC Question 34: Is it the NRC’s position that a valve ONLY requires Fail Safe testing if, the Fail position is a safety related position? Is it the NRC’s position that a valve ONLY requires Fail Safe testing if, the Fail position is a safety related position?

82. 82 ISTOG QUESTIONS –2007 NRC Question 35: What is the NRC’s position regarding a pump being tested during refueling and the pump enters the ALERT range? Typically, the requirements are to double the test frequency UNTIL the cause of the condition is determined and the condition corrected. What is the NRC’s position regarding a pump being tested during refueling and the pump enters the ALERT range? Typically, the requirements are to double the test frequency UNTIL the cause of the condition is determined and the condition corrected. However, as can be plainly seen, to double the frequency would require the plant to shutdown mid-cycle. Would it be acceptable to the NRC to perform an analysis and based on the determination that the pump would be able to perform its safety function until the next RFO, to provide written justification and documentation and to continue with the normal test frequency or, would this require some type of exigent relief? However, as can be plainly seen, to double the frequency would require the plant to shutdown mid-cycle. Would it be acceptable to the NRC to perform an analysis and based on the determination that the pump would be able to perform its safety function until the next RFO, to provide written justification and documentation and to continue with the normal test frequency or, would this require some type of exigent relief?

83. 83 ISTOG QUESTIONS –2007 NRC Question 36: What is the NRC’s position regarding extension of frequencies for CV Condition Monitoring and initial frequency? What is the NRC’s position regarding extension of frequencies for CV Condition Monitoring and initial frequency? Is it a requirement based on NRC position that you must NOT exceed 1 cycle extension at a time UNTIL several years have passed with the Initial or can you use previous CV test history to determine the FINAL interval initially? Is it a requirement based on NRC position that you must NOT exceed 1 cycle extension at a time UNTIL several years have passed with the Initial or can you use previous CV test history to determine the FINAL interval initially? NRC Question 37: If a relief request has been denied by the NRC, is it acceptable to “pull back” the relief request and continue on with the proposed test method? If a relief request has been denied by the NRC, is it acceptable to “pull back” the relief request and continue on with the proposed test method?

84. 84 ISTOG QUESTIONS –2007 NRC Question 38: What is the requirement if the NRC has NOT approved the relief request submitted for the start of the next ten-year interval for IST? What is the requirement if the NRC has NOT approved the relief request submitted for the start of the next ten-year interval for IST? Can you implement the relief requested alternative? Can you implement the relief requested alternative? Must you continue to test per the previous method? Exigent relief? Must you continue to test per the previous method? Exigent relief? NRC Question 39: Is it the NRC’s requirement that should “major maintenance” be required to be performed online for a Group B pump that Exigent Relief be requested to restore the pump to Operable status or, can you use a Group A test? Is it the NRC’s requirement that should “major maintenance” be required to be performed online for a Group B pump that Exigent Relief be requested to restore the pump to Operable status or, can you use a Group A test?

85. 85 ISTOG QUESTIONS –2007 NRC Question 40: Is it the NRC’s position that Group B pump tests must be performed with the same methodology as Group A regarding fixing a parameter (flow or dp) and then measuring the other parameter or, can you ONLY measure one parameter and then determine acceptability by ensuring that the measured parameter is within 10% of the reference value? Is it the NRC’s position that Group B pump tests must be performed with the same methodology as Group A regarding fixing a parameter (flow or dp) and then measuring the other parameter or, can you ONLY measure one parameter and then determine acceptability by ensuring that the measured parameter is within 10% of the reference value? NRC Question 41: Is relief required to use a Code Case which has an applicability of Code which is NOT the Code of Record for the plant? Is relief required to use a Code Case which has an applicability of Code which is NOT the Code of Record for the plant? NRC Question 42: Is it the NRC’s position that subsection ISTB-6200 (c) is able to be used WITHOUT prior NRC approval? Is it the NRC’s position that subsection ISTB-6200 (c) is able to be used WITHOUT prior NRC approval?

86. 86 ISTOG QUESTIONS –2007 NRC Question 43: Can MOVs, CVs, AOVs, etc., be included in alternative test methods such as OMN-1, Appendix II, OMN-12…etc., individually (i.e. cherry picking) or, must ALL valves being included in the applicable alternatives should the alternative be chosen? Can MOVs, CVs, AOVs, etc., be included in alternative test methods such as OMN-1, Appendix II, OMN-12…etc., individually (i.e. cherry picking) or, must ALL valves being included in the applicable alternatives should the alternative be chosen? NRC Question 44: Is it the NRC’s position that Atmospheric Dump Valves and Auto Depress. Valves ONLY require exercising in lieu of Stroke Time testing and fail safe testing IF the valves are designated as Category A and B safety relief valves? Is it the NRC’s position that Atmospheric Dump Valves and Auto Depress. Valves ONLY require exercising in lieu of Stroke Time testing and fail safe testing IF the valves are designated as Category A and B safety relief valves?

87. 87 ISTOG QUESTIONS –2007 45. Regulatory Interface Section Question NUREG 1482, Rev. 1, Section 5.9, Pump Testing Using Minimum Flow Return Lines With or Without Flow Measuring Devices, identifies that pump parameters shown in ISTB-3000-1 must be measured and evaluated to determine pump condition and detect degradation. The following sentence in the NUREG states that pump differential pressure and flow rate are two parameters that are measured and evaluated together to determine hydraulic performance. Table ISTB-3000-1, Note 1 for the Group B Test, states differential pressure or flow rate shall be measured and determined for all pumps, except positive displacement. This note appears to contradict the above statement.

88. 88 ISTOG QUESTIONS –2007 45. Regulatory Interface Section Question Given a group B centrifugal pump, where the group B test is performed on a non-instrumented, fixed resistance minimum flow bypass line, per the Code recording and evaluating differential pressure only appears to be acceptable. While on the 1989 Code we had an approved relief request to perform testing in this fashion provided a full flow test was performed each refueling outage. When updating to the 1998 Code relief was not requested as the Code changes were in essence implementing the requirements of the relief.

89. 89 ISTOG QUESTIONS –2007 45. Regulatory Interface Section Question Based upon recent discussions it appears as if the NRC still expects both flow and differential pressure to be recorded for group B pump tests. Please comment if this is an expectation and if so when requesting relief since all Code requirements are met, what is the basis for the relief request? NRC Question 45: Any comments on the above?