update 10/28
(new)-Hope creek and Salem 1& 2 is the second largest nuclear facility in the USA. They own Peach Bottom, Salem 1& 2 and Hope Creek. They have a high plant number for such a small company. I'll bet you per stockholder to nuclear plant ratio, PSEG has the highest rate in the nation. They have a very high nuclear plant exposure. Man, abutting the cheap Marcellus shale gas field and Pennsylvania...cheap electricity??? Maybe the cheap natural gas plants can bail out their nukes...
(New)Forgot- asked why there never was a licence event report (LER) on the H SRV. The failure of the H SRV last Sept 2014 was a "special interest" to the nuclear industry directly after shutdown according to the NRC inspection report...but why no LER? He verified no H SRV LER on the docket. He thought it surprising it wasn't on the docket. He thought NRC regulations don't required federal reporting on this kind of problem. I am telling you, it is a cover-up and the rules for NRC LER reporting is part of the problem. They corrupted public transparency...
"So a special or stand in Hope Creek NRC resident called me up.
- Basically Hope Creek were in negotiation with a European firm on replacement SRVs (identical to Pilgrim’s now in plant)…the Europeans backed out because they couldn’t meet our quality standards.
- Then Hope Creek approached Target Rock for a SRV contract for the 2 stage replacement. They pulled out of the discussion without a reason.
I gave him the SRVs setpoint admin scenario. He gave me all the nuclear analysis saying they were safe. I said safe for me is following all the plant licensing and tech specs without question first. If the written rules aren’t right, you do a written evaluation, then change the rules. But you have to follow tech spec. What if in the control room you came upon information one SRV setpoint was at 5%, is the valve inop? On the second one going out, are they required to shut down? What does the actual tech specs required the plant to do? Then I told him the situation with H SRV testing. Said it went to 3.6% at 7 months. When does the valves go out of tech specs, at the one month or six months? HC last testing has a 71% failure rate. At the 8 month time frame will HC with two inop SRVs and have to shutdown. Hope Creek for about a decade has been whining about the need to replace the 2 stage.
This so called stand in NRC resident is siloing information in his head just to career wise survive. This information goes into this cubby hole and that information goes into another cubby hole…but never shall all the information in my special cubby holes meet.
Does the uncertainty of not knowing the actually set point lift point require an immediate plant shutdown?
That is when he explained to me these are complicated matters, he will have to get back to me in a few days.
I am thinking this is a huge cover-up. At least the Pilgrim style model, there is no new replacement to be had on the market. It probably all over the BWRs, I see similar issues with the PWRs with the pressure operated relief valves (PORV).
Everything is always an information gather campaign?
I’ll bet you the liability for making these kinds valves is too large for any manufacturer to consider supply the nukes. What if one of our valves caused a trillion dollar plant meltdown?"
Another update:
We are in that SRV setpoint lift pressure inaccuracy admin error I talked about the other day. Them idiots. That leaking Hope Creek H SRV last sept 5 2014…they replaced it with a refurbished one. Started up and seven months later they entered the normal outage. Massive SRV setpoint lift inaccuracies in the refueling outage forced them to test all 14 SRVs. They tested the Sept 2014 installed H SRV who was only in the plant for seven months. It failed the lift pressure test accuracy with a 3.6% (while in the plant for only seven months). On two SRVs being declared inop they are required to be shutdown within 24 hours. Hope Creek SRVs had a 71% lift accuracy failure rate this period. Some huge numbers too. How can Hope Creek demonstrate they are within Tech Specs say at the 8 month point …prove they are safe and fully within tech specs? These guys are the same model SRVs as Pilgrim. They have been operating for 5.5 months now…how many inop SRVs are in the plant now?
The admin scenario I was talking about in Pilgrim. The SRV testing facility calls Pilgrim saying the SRVs you sent us have all been tested, inspected...they are good for plant operation and well within tech specs. Pilgrim installs these and restarts. The testing facility calls six months later saying we made a terrible admin mistake. The A SRV was mistakenly set to lift at 5%. Plus or minus 3% pressure is the tech spec limit. It is outside your tech specs and you need to call the valve inop.
What would Pilgrim be required to do per tech specs?
Tech Specs says all SRVs need to be operable at power and be within 3% lift pressure testing limits. Upon one two SRV being inop, the plant is required to be shutdown within 24 hours. They would have need NRC permission to stay up in power after 24 hours.
Tech Spec SRV lift pressure valve actuation point isn't discoverable at power or fixable.
Works in progress
Update@1pm
You get it with the H SRV valve. In a little over six months of operation, this valve exceeded its tech spec plus or minus 3% limits of 3.6%. It was required to be called inop. The second inop SRV would require the plant to be shutdown per Tech Specs
How many SRVs were lift setpoint inaccurate on Aug 2014? Why didn't they yanking out all the reliefs on the Sept maintenance outage and reset them. How many right now are inop and Hope Creek should be required to be shutdown.
- April 2012: startup from refueling
- Sept 5, 2014: leaking SRV ‘H’ shutdown
- April 11, 2015-May 13: normal refueling. 32 day outage
***Hope Creek from the Sept 2014 end of maintenance outage till beginning of April 2015 normal refueling outage. The amount of time it takes for a SRV setpoint lift pressure accuracy to be within tech specs and then get to 3.6% over tech spec lift limits.
Result: 218 days
It is 218 days from the start date to the end date, but not including the end date
Or 7 months, 6 days excluding the end date
***Hope Creek from end May 2015 normal refueling till today
Result: 167 days
It is 167 days from the start date to the end date, but not including the end date
Or 5 months, 14 days excluding the end date
***Pilgrim from end of normal May 2015 refueling till today
Result: 154 days
It is 154 days from the start date to the end date, but not including the end date
Or 5 months, 1 day excluding the end dat
LER 2015-004-01
F013H 1148 1108 1074.8-1141.2 3.60%
"As-Found Values for Safety Relief Valve Lift Set Points Exceed Technical Specification Allowable Limit."
Technical Specification (TS) 3.4.2.1 requires that the safety function of at least 13 of 14 SRVs be operable with a specified code safety valve function lift setting, within a tolerance of+/- 3%. Action (a) of TS 3.4.2.1 specifies "With the safety valve function of two or more of the above listed fourteen safety/relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours." Therefore, this is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by TS.
CORRECTIVE ACTION
1. All 14 SRV pilot stage assemblies were removed and replaced with pre-tested, certified spare pilot valves(H1R19).
2. Evaluate options for the replacement of the currently installed Target Rock two-stage SRVs with a design that eliminates setpoint drift events exceeding +/-3% and improve SRV reliability. The replacement schedule will be developed after a suitable valve is identified.
I am still working on this...
So how would say five SRVs discharge piping severing effect all the accidents. A stuck open SRV and a severed SRV discharge line?
This is a much worst accident than the NRC portrays and it should have gotten a much bigger inspection...
Remember LaSalles torus temperature stratification incident...
They had to use torus cooling to compensate for the leaking SRV throughout the cycle and they were surprised with hearing steam bubble collapse booms in the torus.
Bet you those steam bubble vacuum booms sound very similar to the normal operation of HPIC and RCIC.
I am shocked they had to use safety systems(torus cooling)excessively just because they were too cheap to fix the SRV right and then failed to immediately shutdown on the fist indication the H SRV was leaking.
Hope Creek
February 5, 2015
Pg11
(NCV 05000354/2014005-01, Failure to Identify and Correct a Condition Adverse to Quality Associated with Safety Relief Valve Discharge Piping Misalignment)
***and the August 2014 power reduction due to a safety relief valve indicating open.
***The SRVs are Target Rock Model 7567F two-stage SRVs
1R15 Operability Determinations and Functionality Assessments (71111.15 – 3 samples)
a. Inspection Scope
Findings
Introduction. A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, “Corrective Action,” because PSEG did not promptly identify and correct a condition adverse to quality. Specifically, PSEG did not initiate a NOTF or perform an evaluation of a cold spring condition
The SRV and its discharge piping were not line up on installation of the tested valve in 2012... the relief and it discharge piping was out of alignment by some two inches. Hope Creek used the tremendous force of a "come-along" chain to jack the valve and piping together for attachment. One doesn't know the misalignment before the the "come-along". This damaged the 2 stage SRV. This is what happens when you have gorilla maintenance employees and a initially poorly designed valve. Then you had incompetent control room people who never could make the right safety call from 2012 to Sept 2014. This is very similar to the bungling of the Pilgrim SRVs since new installation in 2011 with the length of time the licencee and NRC took to come to terms with their SRV problems.
Check out the SRV set point lift pressure inaccuracy inops in Licensee Event Report 2015-004-01. Ten out fourteen failed their tech spec acquirement. They needed to be declared broken at greater plus or minus three percent inaccuracy. Severity one percent failed tech spec testing. Upon discovering more than one SRV was outside tech spec they were required to shutdown and fix them. A large number of SRVs being outside Tech Specs were substantially outside plus or minus 3%.
I consider the "identification occurrence" as being corrupt and a document falsification. The "event date" was sometimes during "plant operation". Because they have no means to know or proof when the tens valve went broken, they would have to make a conservative guess they went broken one day after startup from outage after in 2012.
IDENTIFICATION OF OCCURRENCE
Event Date: June 2, 2015
Discovery Date: June 2; 2015
So in this operating period (18 month) with Hope Creek's model 7567F (Pilgrim too)they has extremely dangerous leaking H SRV and other 9 failed testing valves.
***Where the hell is the Licence Event report(LER)on the leaking 'H' SRV valve???
Just saying, 'H' SRV valve was inop before they even started up.
found in the ‘H’ SRV discharge piping during the valve’s replacement in 2012. This condition that occurred during installation was determined to be the cause of a leak on the main seat of the newly installed SRV. The leak proceeded to degrade during the operating cycle and ultimately caused Hope Creek to shut down and replace the SRV on September 5, 2014.
Description. The target rock
model 7567F two-stage, pilot-operated SRV consists of two assemblies: a pilot
stage assembly and a main stage assembly. These two assemblies are directly
coupled to provide a unitized, dual function SRV. The pilot stage assembly is a
pressure sensing and control element, and the main stage assembly is a system
fluid-actuated reverse seated angle globe valve which provides for the pressure
relief function or system depressurization at full rated flow. This model SRV
has a set pressure range of 1025 to 1190 psig and weighs approximately 1100
pounds. The main stage disc is tightly
seated by the combined forces exerted by the preload spring and the system
internal pressure acting over the area of the valve disc.
_________________________________________________________________________________
***2014005 February 5, 2015-The inspectors reviewed PSEG’s ACE, SRV work history, procedures and previous CAP evaluations and determined that PSEG’s conduct of maintenance in WO 60097071 should have generated a NOTF to document and evaluate the discharge piping misalignment found when removing the ‘H’ SRV in RF17. The inspectors also identified a note in Section 5.2.3 of MA-AA-734-458, Pressure Relief Device Removal and Installation, which states that “discharge piping should not cause any bending or apply any cold spring to the relief valve. Any cold spring or pipe distortion should be brought to the attention of supervision.” The inspectors determined that PSEG should have evaluated the misaligned SRV discharge piping as a potential condition adverse to quality.
***05000354/2015002-On April 15, 2015, PSEG
NDE personnel were attempting to perform an ASME Code required ultrasonic examination
of a weld on the ‘A’ SRV inlet piping, just below the bolted flange, when NDE
personnel discovered tooling marks in the area of the weld preventing them from
performing the weld examination.
In addition, the
inspectors identified that PSEG procedure, HC.MD-CM.0006, Sections 5.4 Valve
Body Removal, 5.5 Valve and Piping Inspections and 5.6 Valve Body Installation
contained supervisory hold points for maintenance supervision to verify work
task completion. Specifically, the inspectors identified that Sections 5.5 and
5.6 required visual inspection of the SRV inlet and outlet piping as well as
notes that any nicks, pits and grooves that are greater than 0.062 inches in
depth are to be evaluated by the engineering staff.
The inspectors observed
that each use of the torque tool on the RCS piping likely caused unquantified
degradation to the affected RCS piping. The inspectors’ review of PSEG’s
technical evaluation, SRV work history, and procedures determined that these
tooling marks should have been identified and evaluated as a condition adverse
to quality by PSEG prior to April 2015, and as early as the first usage of the
torque tool for SRV maintenance applications which started per HC.MD-CM.AB-0006
Revision 17 in October 2004. In addition, the inspectors identified that PSEG
procedure, HC.MD-CM.0006, Sections 5.4 Valve Body Removal, 5.5 Valve and Piping
Inspections and 5.6 Valve Body Installation contained supervisory hold points
for maintenance supervision to verify work task completion. Specifically, the
inspectors identified that Sections 5.5 and 5.6 required visual inspection of
the SRV inlet and outlet piping as well as notes that any nicks, pits and
grooves that are greater than 0.062 inches in depth are to be evaluated by the
engineering staff.
_____________________________________________________________________________________
On August 12, 2014, an equipment
operator on reactor building rounds noted a loud banging noise emanating from
the torus room area between the 54’ and 77’ elevations. Further investigation
by operations within the torus room revealed the noise to be loudest around azimuth
340 degrees, with a pattern of a loud bang followed by several softer, quieter
bangs. The loud bangs occurred at a frequency of every 5 seconds. PSEG
conducted a review of plant parameters and correlated the noise with an
increased frequency in the need to run suppression pool cooling and torus
letdown due to increases in torus heat
input and level since February 2014.
PSEG initiated an investigation to determine the potential causes of
the noise. As part of this investigation, PSEG developed a failure mode causal
team (FMCT) with input from subject matter experts throughout the industry to
identify potential causes of the noise. Industry operating experience (OE) was
also reviewed, indicating similar events at Hatch and Millstone. The FMCT
determined that the two most likely causes of the noise were either cycling of
the ‘H’ SRV tailpipe vacuum breakers (VBs) inside primary containment (elevation
112’) or ‘H’ SRV leak by resulting in a water chugging event within the SRV
discharge pipe T-quencher located inside the torus. OE from Hatch and Millstone
indicated that if the VBs were cycling, failure of the VBs could occur within
30 days of the appearance of the noise, causing a potential direct pathway of
any steam flow through ‘H’ SRV to the drywell instead of being dissipated by
the water volume of the torus. Due to this potential failure mode, PSEG made
the decision on August 25, 2014, to conduct a planned maintenance outage on
September 5, 2014, to further troubleshoot and repair the source of the noise.
After shutting down the plant on
September 5, 2014, PSEG refuted the cycling SRV VB potential cause by
conducting walk downs at rated pressure inside the drywell and performing inspections
of the ‘H’ SRV VBs to verify they had not been cycling. After completing
detailed visual inspections inside the drywell and torus, PSEG concluded that
the most probable cause of the torus noise was excessive leakage past the ‘H’
SRV main seat inducing a water chugging event within the T-quencher. This water
chugging event occurred when significant quantities of steam reached the water
in the T-quencher initiating a repeating condensate induced water hammer inside
the T-quencher. PSEG removed and replaced the ‘H’ SRV main and pilot valve assemblies,
and had both assemblies tested offsite. The results of the testing yielded 0.05
gpm and 2.35 gpm leakage past the pilot and main seats, respectively, totaling
approximately 2.4 gpm or 1200 lbm/hr at 1000 psig.
PSEG’s investigation of the ‘H’
SRV main seat leakage identified the main disc as being severely steam cut. The
apparent cause evaluation determined the most likely cause of the steam cutting
to be the existence of cold spring in the tailpipe of the ‘H’ SRV during the
last replacement of the valve in RF17 (April 2012) under WO 60097071. This WO
documented that the ‘H’ SRV tailpipe was misaligned and discussion with maintenance
found that a “come-along” was used to adjust for piping misalignment following
removal of the valve. PSEG determined that a large moment force was applied to
the SRV main during installation, causing the initial leak on the SRV main
seat, which then degraded during the operating cycle. During the removal of the
‘H’ SRV main assembly in September 2014, the misalignment of the discharge piping
was documented in NOTF 20661387 as off by 1.5” horizontally and 1.25”
vertically. PSEG found that the ‘H’ SRV discharge piping spring can was not
pinned during the removal process in 2012, and if it had been pinned prior to
removal, it could have prevented any cold spring or piping misalignment during
reinstallation of the new SRV. PSEG’s apparent cause evaluation (ACE) determined
that the SRV installation and removal procedure does not include steps to pin
the spring can prior to SRV piping disassembly.
The inspectors reviewed PSEG’s
ACE, SRV work history, procedures and previous CAP evaluations and determined
that PSEG’s conduct of maintenance in WO 60097071 should have generated a NOTF
to document and evaluate the discharge piping misalignment found when removing
the ‘H’ SRV in RF17. The inspectors also identified a note in Section 5.2.3 of
MA-AA-734-458, Pressure Relief Device Removal and Installation, which states
that “discharge piping should not cause any bending or apply any cold spring to
the relief valve. Any cold spring or pipe distortion should be brought to the
attention of supervision.” The inspectors determined that PSEG should have
evaluated the misaligned SRV discharge piping as a potential condition adverse
to quality.
Analysis. The inspectors determined that the inadequate
identification and evaluation of the conditions adverse to quality associated
with ‘H’ SRV discharge piping misalignment found during valve replacement in
2012, was a performance deficiency that was within PSEG’s ability to foresee
and correct. The finding was more than minor because it was associated with the
procedure quality attribute of the Initiating Events cornerstone and adversely
affected the cornerstone objective to limit the likelihood of an event that
upsets plant stability. Also, if left uncorrected, the finding had the
potential to lead to a more significant safety concern. The inspectors
determined that this finding was of very low safety significance (Green) using
Exhibit 1 of IMC 0609, Appendix A, “The Significance Determination Process
(SDP) for Findings At-Power,” dated June 19, 2012, because the finding did not
cause both a reactor trip and the loss of mitigation equipment relied upon to
transition the plant from the onset of the trip to a stable shutdown condition.
Specifically, the ‘H’ SRV safety-related function, relied upon for accident
mitigation and pressure relief, remained operable.
This finding has a cross-cutting
aspect in the area of Problem Identification and Resolution, Identification,
because PSEG did not identify this issue completely, accurately and in a timely
manner in accordance with the CAP. [P.1]
Enforcement. 10 CFR 50, Appendix B, Criterion XVI, “Corrective
Action,” requires in part, that measures shall be established to assure that
conditions adverse to quality, such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and non-conformances are promptly
identified and corrected. Contrary to the above, PSEG failed to promptly
identify and correct a condition adverse to quality. Specifically, PSEG did not
initiate a NOTF or perform an evaluation of a cold spring condition found in
the ‘H’ SRV discharge piping during the valve’s replacement in 2012. This
condition was determined to be the cause of an initial leak on the main seat of
the new SRV during installation, which then proceeded to degrade during the
operating cycle and ultimately caused PSEG to shut down and replace the SRV on
September 5, 2014. PSEG’s corrective actions included replacing the ‘H’ SRV,
providing training to all maintenance crews responsible for SRV work, and
adding steps to the SRV removal and installation procedure to: 1) generate a
notification for the identification of any piping misalignment; and 2) pin the
discharge piping spring can prior to SRV removal. Because this finding was of
very low safety significance and because it was entered into PSEG’s CAP as NOTF
20661387, this violation is being treated as an NCV, consistent with the NRC
Enforcement Policy. (NCV 05000354/2014005-01, Failure to Identify and
Correct a Condition Adverse to Quality Associated with Safety Relief Valve
Discharge Piping Misalignment)
