ISTOG QUESTIONS –2007
1. 5-YR Frequency of Class 1 Relief 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.
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.
Our Technical Specifications require the testing of these valves to be
per the IST Program.
1
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 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.
2
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?
3
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.
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.
4
ISTOG QUESTIONS –2007
2. AFW Flow Instrumentation When on Miniflow
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.
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:
5
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?
6
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:
3/8/07
5/2/07
8/2/07
CV1804A
3.22
3.84
4.17
CV1804B
3.19
3.85
4.97
7
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.
8
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.
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?
9
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.
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.
10
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.
(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).
11
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.
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.
12
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)
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?
13
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?
14
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?
15
ISTOG QUESTIONS –2007
6. Cooling Water/Service Water 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?
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?)
16
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.)
17
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.
18
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?
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?
19
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.
20
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?
21
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.
The affect on the closing stroke time would be estimated and it
would be well within the design basis stroke time.
22
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 postmaintenance stroke time test?
NRC Question 9:
Would the NRC consider this an acceptable practice?
23
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.
24
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?
25
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%.
26
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.
27
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)?
28
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?
29
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.
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.
30
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?
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?
NRC Question 12:
Any comments to the above?
31
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".
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?
32
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?
33
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
Model --DRV-B
Size -- 24"
System Application --check valve for saltwater pump
Service Condition --saltwater @ 35psi
NRC Question 14:
Any comments on above?
34
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.
Each pump test is reviewed by a pump engineer and the group
supervisor.
35
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.
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?
36
ISTOG QUESTIONS –2007
15. Observations of Surveillance Tests (IST's)
2.
3.
If you have a separate group that performs the pump
tests, does the pump engineer(s) additionally observe
the pump tests during performance?
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?
37
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).
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).
38
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.
In the latest version of ISTC App. III Section 3300 and 3310 there is
NO specific discussion of the IST interval relative to HSSC.
39
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.
40
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).
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?
41
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?
42
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.
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.
43
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?
44
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.
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.
45
ISTOG QUESTIONS –2007
18. Preconditioning Question
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
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..."
46
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?”
47
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.)
48
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
NRC Question 19:
Comments?
49
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.
50
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.
NRC Question 20:
Comments?
51
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?
52
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?
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.)
Can you provide further clarification or guidance?
53
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.
54
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?
55
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.
56
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?
Does the NRC consider Diesel Fuel Oil Transfer Pumps to be “skid
mounted”?
57
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?
58
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?
59
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?
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?
60
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?
61
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?
62
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.
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.
63
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?
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?
64
ISTOG QUESTIONS –2007
26. Testing During Power Ascension
Clarification:
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.
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.
65
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?
66
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?
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?
67
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.
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.
68
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.
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 opened (and
timed) to place the pump in a ready condition.
69
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 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?
2. If not, do you isolate steam the turbine well stroke timing the
pump’s discharge throttle valves?
70
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?
71
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.
72
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).
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)?
73
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?
74
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.
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?
75
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:
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?
76
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.
77
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.
a. On what frequency are you testing these valves?
b. What was your justification if deferred to a cold shutdown or
refueling outage?
NRC Question 31:
What is the NRC’s position regarding the above response? Is it
acceptable to time as stated above?
78
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?
79
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?
80
ISTOG QUESTIONS –2007
NRC Question 33:
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?
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?
81
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.
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?
82
ISTOG QUESTIONS –2007
NRC Question 36:
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?
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?
83
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?
Can you implement the relief requested alternative?
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?
84
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?
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?
NRC Question 42:
Is it the NRC’s position that subsection ISTB-6200 (c) is able to be
used WITHOUT prior NRC approval?
85
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?
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?
86
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.
87
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.
88
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?
89