ML20137X514
| ML20137X514 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 12/04/1994 |
| From: | NRC |
| To: | Selin I, The Chairman NRC COMMISSION (OCM) |
| Shared Package | |
| ML20137X493 | List: |
| References | |
| FOIA-96-351 941204, NUDOCS 9704220064 | |
| Download: ML20137X514 (3) | |
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. 'e, l TO: Honorable Mr. Ivan Selin, Chairman Nuclear Regulatory Commission Washington, D C 20555 K
DATE: December 4,1994
SUBJECT:
NRC Violations at Salem Nuclear Plant I had drawn your attention to the litatiy of NRC violations at Salem Nuclear Power Plant owned by PSE&G and written a very detailed letter with attachments o 1994. This letter was also provided to NRC Region 1.
While NRC Regioni acknowledged the receipt of the letter in August, I have receive no progress report on my complaint from Region 1. During such a long period, PSE&G low
! level management would havc had enough time to doctor key evidence or coach employees to lie about the NRC violations.
You or your office has not even acknowledged the receipt of this detailed complaint. It took my enormous time and courage to document the NRC violations by this licensee. Your
- glowing tribute to the top management of PSE&G emboldened them to fire all employees j who ever complained about Nuclear Safety. You may want to read your closure comments
' during your meeting with top PSE&G management. How wrong were these comments, could be explained by me ifyou could grant me 15 minutes ofyour valuable time. After misunderstanding your comments, the PSE&G top management required submittal of names in each group, approximately 10% , which the Supervisors / Managers wanted fired for any reasons. While you and your comments required PSE&G to cleanup and fire those employees who have caused nuclear incidents repeatedly at Salem to improve Salem nuclear Safety record , the PSE&G management fired old age (over 40 years), minority black, excessive sk time. Selected were black employees to make departments 100% white, person with terminal cancer whose medical had mn out previously, person who had 6 month recovery from kidney removal. Many persons were selected because of their high salary due to long term employment at PSE&G, some dared to complain to the PSE&G supervision 4
about unsafe or impmdent decisions. There was not one single person who was involved in j those previous events at Salem which really is the concern of Salem.
On or about April 20, there was criminal concealment of a NRC violation which was being delivered to the Salem Control Room by responsible Engineers as an incident report. At the 4.
last minute Salem management stopped it from being delivered to the Control Room. These i
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.t g managers decided that if the Incident Report is delivered to the Control Room, it will be picked up by NRC residents and will reach in the hands of AIT team investigating the April 7 alert event at Salem. Based on this, PSE&G will not be able to start the Unit and thus suffer millions of Dollars as loss due to delay in starting the Unit. If the NRC ever finds out, it will be small fine less than hundred thousand Dollars. This suppression of material information was illegal and violated several NRC regulations. I brought up this to my acting Supervisor and Manager who promised me to talk to these managers but actually took no action. I have documented in my earlier letter to you.
Your closing remarks required actions against all those employees who cause repeated nuclear safety incidents, drain NRC resources and cause loss of confidence in safe operation of Salem and according to the license conditions. Those people are still working and may even be promoted. Out are those helpless people, sick with no health insurance, too old to be hired by another employer for comparable job, minority employees who have no chance todays' job i market and economy. Gone are those promises oflifetimejobs at utility company which were l made to lure these people when gud employees were difficult to find.
I basically want to draw attention to your closing remarks made in your meetings with the top PSE&G management. Did you ever intend to have so many helpless employees be fired for i none of their fault. I hope you sleep fine because so may of these people do not. I earnestly request you to reflect on how much wrong these people been done by misunderstanding your remarks. The Chairman of this company / licensee may have saved his ownjob because Board of Directors ofPSE&G were meeting on or around July 18,1994 to ask for his resignation if he did not take bold action of firing all appropriate employees who are causing the loss of confidence of the NRC in PSE&G as licensee for Salem.
I would very much appreciate if the NRC commissioners would grant me a hearing otherwise '
not too many citizens / employees would dare to complain the nuclear safety problems at nuclear power plants. The result would ofcourse be another TMI or Salem alert,
. C: Honorable U S Senator Joseph Biden Chairman PSE&G Mr. J E Ferland Counsel, PSE&G, Mr. Henry L. San Giacomo Administrator USNRC Region 1
. - . - . -_ - - - -.. - - ...- _ - - .- _ . _ - . ~ _
. e l OFFICE OF THE SECRETARY
, , CORRESPONDENCE CONTROL TICKET PAPER NUMBER: CRC-94-1247 LOGGING DATE: D 13 94 l l ACTION OFFICE: EDO/ TIM MARTIN ,
AUTHOR:
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- ADDRESSEE
- CHAIRMAN SELIN 7 ,.
LETTER DATE: Dec 4 94 FILE CODE: IDR-5 SA EM
SUBJECT:
NRC VIOLATIONS AT SALEM NUCLEAR PLANT j ACTION: Direct Reply l
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'8 ,, NUCLEAR REGULATORY COMMISSION Taylor I
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%*****/ June 3, 1994 Blaha C[IMar44n, RI CHAIRMAN Russell, NRR cc: RCooper Liebennan, OE JWiggins Jordan, AE0D The Honorable Joseph R. Biden, Jr. 6/20/94-TTM '
United States Senate l 8 Washington, D. C. 20510 ED0 R/F
Dear Senator Biden:
On behalf of the commission, I am responding to your letter dated May 18, 1994, concerning the operation of Public Service Electric and Gas Company's (PSE&G) Salem Generating Station. Upon receipt of that letter, I asked the staff to prepare a direct response to
, the points in your May 11 and May 18 letters. I have enclosed (Enclosure 1) the staff's response to the is' sues expressed in ~ l both letters. '
I realize that some of the points in'your May 11, 1994, letter
- were not addressed as clearly as they could have been in the NRC staff's reply to you dated May 14, 1994; nevertheless, I want to 4
assure you that the staff had fully considered the information provided in your letter of May 11 prior to granting permission to PSE&G to restart Salem Unit 1 on May 14. In addition, a public i briefing was held for the NRC Commissioners by the staff and the l licensee on May 9, 1994. The Commission was satisfied with the j staff decision to grant PSE&G permission to restart Salem Unit 1 !
on May 14, 1994. As was noted in the staff's May 14 letter to you, enforcement action related to this event is still under consideration. I 1
The staff made the decision to allow Salem Unit 1 to restart following completion of the Augmented Inspection Team's (AIT) l review of the event. The issues that required resolution prior to restart of Salem Unit 1 involved four principal concerns: l
- repair and improvement of certain components (i.e.,
) powe'r-operated relief valves, the controllers for the main steam atmospheric relief valves, and the solid state protection system);
e procedural improvements related to operator actions (e.g., guidance addressing conditions that affect the operation of the circulating water system, vessel level 4 monitoring, loss of condenser vacuum, and turbine trip);
e improvements in operator training (including communications, resource management, and revised f
procedures) relative to the lessons learned from this i event; and h \l 9
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e management effectiveness (i.e., immediate onshift l management oversight).
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Enclosure 2 summarizes the specific details of actionsThe completed NRC staff l' by the licensee evaluated and related where to these areas of concern. inspected each of the licensee's applicable, j restart related activities before authorizing restart.
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Although all of your points are addressed in Enclosure 1, l like to speak specifically to two technical points that you
- raised. First, problems with the power operated relief valves (PORVs) were found as a result of questions raised by the However, AIT and
- subsequent review by the licenses following this event.
the PORVs were cycled over 200 times during the event and remained functional. The PORVs served their function of preventing a challenge to the primary safety valves asThe the primary safety valves did not open.during the event.
components of the PORVs demonstrating wear or damage were h it.
replaced with Todified internals prior to restart of t e un The second point is the licensee's continuing problems with grass l clogging the circulating water screens during certain times of the year. This challenge falls within the plant's design basis.
The plant design and operator actions should have been able to respond to this challenge without experiencing the difficulties associated with the April 7 avant. Therefore, the staff has required and the licensee has taken several actions to prevent this type of event in the future, including procedure changes, design changes, and enhanced operator training.
In both of your letters, you voiced concerns about the effectiveness of the management of Salem and the NRC's role in effecting change. The Commission believes that the level of performance at Salem can and should be improved; nevertheless, the concerns have not reached the level that would In require order to shutdown of the facility or denial of restart.
determine whether a licensee requires increased surveillance through the NRC's inspection process, the NRC has established a
} formal program whereby senior NRC managers review the agency's observations and findings regarding operating nuclear reactors and plan a coordinated course of action This processforisthose plants currently whose being performance is of concern. applied to Salem to determine if additional sur facility is required.
While a review of the Unit 1 issues as they applied the NRCto Salem Unit staff did 2 was not a condition for restart of Unit 1, This 1 review the Unit 1 issues as they applied to Salem Unit 2.The procedure "D" in Enclosure 2.
matter was identified as item 3
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3 revisions and operator training enhancements resulting from the event have been implemented at Unit 2. When Unit 2 is shut down for refueling in October 1994, we expect that these hardware modifications will be performed. l I hope you have found this letter responsive 1994 to your concerns. I f look forward to meeting with you on June 8, to discuss these )
1 and any other issues relative to this matter.
Sincerely, I
Ivan Selin
Enclosures:
- 1. Detailed response to 1 questions and concerns
- 2. May 14, 1994, enclosure to letter addressing restart issues l
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- ENCLOSURE 1*
l DVEST10N 1.
Can the licensee prove that it can and will operate the
' plant any differently in the future than it has in the past? f ANSWER:
l The licensee has implemented programs that can result in performance improvements. The NRC believes that the licensee is operating and managing the plant better since the establishment of the Nuclear Department Tactical Plan developed from the findings of the licensee's Comprehensive Performance The CPAT effort was initiated in July 1993 in
, Assessment Team (CPAT).
response to growing NRC concerns with continuing management and performance deficiencies. Examples of performance issues which raised these concerns included (1) the frequency of HRC Augmented Inspection Team responses (one ,
per year since 1991); (2) the higher than normal plant trip frequency exhibited at Salem; and (3) other recurring deficiencies that caused the NRC to question management's ability to effectively resolve problems.
j The Tactical Plan outlines the agenda to achieve meaningful changes in the way While i
PSE&G conducts the management and operation of the Salem facilities.
I some aspects are currently in progress (such as restructuring of several departments te dedicate personnel resources to each Salem plant, acquiring additional nuclear department staff, and re-evaluation of currently assigned supervisors and managers for effectiveness and ability), the licensee has
'1 i Many of the points of this enclosure may be visualized more clearly by reference to the diagram included after Enclosure 1.
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OUESTION 1. (Continued) l For example, the former completed some significant short-term actions.
General Manager-Salem Operations was replaced by the current Vice President-Nuclear Operations, several supervisory and technical personnel were replaced or reassigned in an effort to affect bet.ter quality of operations, supervisors J f
and managers have been directed to spend more time in direct management and oversight of activities, and additional department managers have been assigned Other to the Maintenance Mechanical and Maintenance Controls organizations.
changes include the required management review and approval of troubleshooting )
plans and procedures, and the initiation of the Augmented Independent Oversight function to provide continuous coverage of plant activities.
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While none of these changes, taken or planned, provides absolute assurance that the licensee will be able to improve, NRC believes that the licensee has and will continue to operate the Units safely.
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00ESTION 2. While the documentation offers some insight into Salem's ,
operations, it does not provide any statement of conclusions l or analysis upon which a restart decision should rest. ;
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Notably, the licensees's full submittal was received by your l office on May 13, 1994; the NRC's analysis was completed that same day. Given the short time frame for review, I !
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question the degree of confidence that you could have gained j in PSE&G's ability or even intention to correct operational problems at the Salem 1 facility.
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l ANSWER:
l The Enclosure to the staff's letter to you dated May 14, 1994, provided the
! restart issues that were identified by the staff for resolution prior to !
l restart. The Enclosure provided a statement of the agency's conclusion for each item based on an assessment of the licensee's submittals on the matter and concurrent independent inspection or assessment of the specific issue or
! activity.
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" The NRC's analyses of the issues and restart decision were not completed in i
one day. While one of the licensee's submittals (which provided only supplemental information, as requested by the NRC staff) was dated May 13 j 1994, the agency's assessment of the licensee's readiness for restart actually
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O began when the NRC's Augmented Inspection Team (AIT) completed its on-site '
) inspection activities on April 21, 1994. Since that time, the NRC staff was continuously involved, monitoring the licensee's corrective actions, i
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00ESTION 2. (Continued) conducting an inspection associated with restart issues, and assessing PSE&G's resolution of the technical issues that were contributors to the event.
l Additionally, the staff reviewed and assessed other licensee submittals that preceded the May 13 submittal (i.e., submittals dated April 25, 29, and May 10,1994). Further, on April 26 and May 6,1994, public meetings were held with the licensee; and on May 9, a public briefing was held for the NRC
' Commissioners by the staff and the licensee. Thus, the staff's efforts in the preceding weeks, during the course of normal business, enabled them to provide a timely response to the licensee's request to commente restart activities in their second letter dated May 13, 1994.
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a OUEST10N 3. A major deficiency of your letter is that it does not assure me that the NRC will take any responsibility in the event that Salem encounters future problems, nor does it make any commitments for strong Agency intervention if such problems occur.
- ANSWER
The licensee is solely responsible to operate the nuclear power plants safely It has always been the NRC's pursuant to their operating license.
- responsibility to license and regulate nuclear facilities to protect public 4
1 health and safety and the environment. The NRC staff takes that responsibility very seriously. Accordingly, the NRC staff is prepared to take any licensing or enforcement action, as permitted by our statutory authority, to ensure that public health and safety are maintained and not compromised by Our ability and willingness to exercise the operation of a nuclear facility.
lj our authority, when conditions warrant, are evident in NRC actions relative to previous plant shutdowns at Browns Ferry, Peach Bottom, Calvert Cliffs, and If our overall assessment of Salem's performance Indian Point Unit 3.
indicated that the potential existed to adversely compromise public health and il
' safety, the NRC ' staff would act promptly to ensure that the facility was If maintained in a shutdown condition until the issue was resolved.
I warranted, the NRC staff would also impose the appropriate enforcement sanctions in accordance with the NRC Enforcement Policy as described by 10 CFR 2, Appendix C.
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DUESTION 4. Why did the manufacturer recommend a change in the old
' material (17-4 PH) that had been used since the early
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1980's? l l
l ANSWER:
The licensee installed, as original equipment during plant construction, PORVs I
In 1982, in f containing 17-4 Precipitation Hardened (PH) steel internals.
response to NUREG-0737 Action Item II.D.1, the licensee replaced the existing l
plugs and stems at Unit I and Unit 2 with stellite clad 304 stainless steel l
' - plug and stem assemblies. In 1993, at Unit 1, the licensee removed the i stellite clad 300 series stainless steel plugs, stems, and the 17-4 PH cages, and installed 420 stainless steel plugs with 316 stainless steel stems and 420 stainless steel cages. The licensee changed to the 420 stainless steel when the loop seals (a "U" shaped section of piping designed to maintain water 4 This against the valve seat) were removed from the inlet piping to the PORVs.
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- changed the operating environment of the valves from water to steam.
licensee, through conversations with the valve vendor, learned that the 420 )
stainless steel internals were available and this material provided improved wear characteristics. Although the existing internals were suitable for the il
- changed environment, the licensee decided to upgrade the valve with the 420 stainless steel material.
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00ESTION 5. What testing had been performed on the new material (420-series) to prove its reliability?
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ANSWER:
The 420 stainless steel, as with 300 series stainless and 17-4 PH stainless, has been qualified to American Society for Testing Materials (ASTM) specifications. In addition, the valve manufacturer cites 20 years of successful use of 420 stainless steel in similar valve configurations used in fossil fuel plants. The manufacturer states that 420 stainless steel internals in this configuration have been used with good success in high Further, the American Society of Mechanical
! pressure feed water systems.
Engineers (ASME) Code Case N-62-4 endorses the use of this material for valve internals.
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h OUESTION 6.
In the aftermath of the failure of the new material, was the NRC database on equipment defects, required to be reported in accordance with 10 CFR 12(sic), reviewed for reports of f
similar problems in other PORV's in other reactors?
ANSWER:
1 Although scuffing and abrasion were apparent on the PORV trim packages (valve internals) removed from the PORVs (IPR-1 and IPR-2), and the anti-rotational embossment on each respective plug element showed signs of cracking, the NRC The fact that staff does not consider that the device or the material failed.
the device cycled over 200 times and performed the function for which it was
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Notwithstanding, NRC did review designed is evidence of successful operation.
its database relative to PORV components and found no reportable defects of NRC contacted Copes-Vulcan, Incorporated, the type experienced in this case.
the vendor of the PORVs used at Salem, and confirmed that no other licensees t
were distributed Type 420 trim package assemblies. The licensee has initiated a report in accordance with 10 CFR 21 relative to the cracking observed on both used and new Type 420 trim package assemblies.
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DUESTION 7, Have other reactors currently using the new material in the PORY been notified of the Salem damage?
ANSWER:
The licensee notified other licensees of the wear that occurre via an electronic bulletin board system (NOTEPAD, which is a system m r The NRC is preparing an f by the Institute of Nuclear Power Operations (IWPD)).
Information Notice to inform other licensees of the Salem evenl implications.
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Is this new material now regarded as inferior to the old 1
DUESTION 8.
material?
l ANSWER:
Series 420 stainless steel is not considered inferior to other previously used materials. However, its application relative to the valve design used in this !
l instance remains to be assessed. Scientists and engineers at the licensee's Maplewood Laboratories and other independent engineering organizations (e.g.,
Westinghouse and MPR Associates) are presently conducting metallurgical examinations, destructive and non-destructive testing, and engineering l
analyses (including computer based finite stress analysis) to evaluate the 1 effect of the observed indications of cracks and wear on the operability of l
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the PORVs under design conditions.
Based on the April 7,1994 transient, PORVs with 420 stainless steel internals 1
are capable of operating more than 200 times under steam and liquid conditions and remain functional despite indications of wear, l
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1 Will the NRC, or manufacturer, direct other licensees to j 00ESTION 9, change the internals, and what material will be recommended for installation?
ANSWER:
4 See response to Question 6.
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- DUESTION 10.
PSE&G indicated that valve internal misalignment may have 2
contributed to'the failure of the valve. Was the valvo installation technique a problem based on the manufacturer ,
l installation specifications or inadequate licensee quality control procedures? And what is being done to correct
' installation problems?
ANSWER:
L Given the tight tolerances required for the valve internals, some scuffing of f I the stem, plug, and cage is not unexpected. However, the degree of abrasion observed in the case of the IPR-1 and IPR-2 valves exceeded what was expected h
by the' licensee for cage-guided globe plug assemblies, even in view of the high number cycles that the valves experienced on April 7,1994.
Notwithstanding, as explained in the Response to Question 6, the valves did not fail and continued tc function. The observed scuffing and abrasion g
i (gouging), particularly as observed on the stem of IPR-2, were of concern relative to the potential for galling sufficient to prevent functioning of the valve.
1 Though not conclusive, the most likely contributor to the condition of the valves was that the licensee's installation technique may not have been sufficient to reduce the potential for misalignment of the valve internals.
While some minor out of tolerance condition (1.5 to 1.8 mils) was no IPR-2 cage, it is inconclusive whether the variance was due to machining
} tolerances or a consequence. of the abrasion. It should be noted that IPR-1
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00ESTION 10. (Continued) i' was observed to have less indication of wear than IPR-2, and was found to be within the manufacturer's specified tolerances.
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'i The installation technique was developed by the licensea, and independent of f
the vendor recommendations. The procedure specified preassembly of the plug e
assembly and packing in the bonnet in an effort to reduce radiation exposures
- to the workers. The level of quality control applied to the installation was I minimal, but the requirements established by the licensee were followed.
j Quality control efforts were performed to confirm that the valve body and I d
internals were free of foreign materials, and that the seal between the valve seating surface and the plug conformed to specifications. Specific quality i
i control checks were not established to confirm alignment of the valve 3
! internal s.
The installation procedure has now been revised to include steps that confirm l} At several steps, I iJ the smooth operation of the valve as assembly progresses.
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the valve assembly is stroked by hand to ensure that the trim package is functioning correctly as the parts are assembled in the body. Upon installation of the packing and final assembly, the valve unit is confirmed to h ].
3 operate corractly by stroking with the valve's air operator.
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l OUEST10N 11. Regarding the PORV's in Unit 2, when was the NRC notified I that the wrong material had been installed?
ANSWER:
i The licensee informed the NRC inspectors that the wrong material had been installed on May 5,1994.
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M 00ESTION 12.
Was this a result of operator notification or a result of my i
! office contacting the NRC with this information?
I ANSWER:
The finding was not the result of either operator notification or of contact l
a with Senator Biden's office on May 13, 1994. The information was developed as 1 i
a result of an NRC inquiry on May 4,1994.
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! The following sequence of events was determined:
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l Initially, the licensee was in possession of six sets of Type 420 PORY trim f 1
f packages (valve internals consisting of Type 316 stem, Type 420 plug, and Type (
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420 cage). During the last Unit'2 outage (2R7-Spring 1993), one pair of trim l
i j packages was expected to be installed in the 2PR-1 and 2PR-2 PORVs.
1 the second pair Subsequently, during the last Unit 1_ '? age (IR11-Fa11 1993),
g P of trim packages was installed in IPR-1 and IPR-2 PORVs.
4 Following the April 7,1994 Unit I trip, the trim packages for IPR-1 and IPR-2 l The valves were found to be scuffed and i PORVs were removed for examination.
1 I cracking was apparent on the embossment on the plug element at the anti-rotation pin. The licensee initially replaced the " damaged" PORV internals with what they believed were the third and last pair of Type 420 trim packages l
in their inventory. (NOTE: The replacement of PORV internals with Type 420 f l trim packages was consistent with a change to the Salem Updated Final Safe 9
Analyses Report which described the PORV internals as Type 420.)
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l OUESTION 12. (Continued) 1 In response to questions from an NRC inspector concerning the status of other 1
- trim packages that remained in inventory, the licensee examined remaining spares on or about May 4,1994, and determined that another pair of Type 420 i trim packages was available in the licensee's warehouse. Examination of those
' The parts revealed cracking on the embossment of one of the plug elements.
discovery of this pair of Type 420 trim packages (with the cracks) led the 4
licensee to: (1) replace the Unit 1 PORV with different materials (i.e., Type 316 stem, Type 316 plug, and Type 17-4 PH cage); (2) and investigate the
- previous 2R7 outage relative to trim package installation. As a result of i
i that investigation, the licensee determined that, due to errors in planning and communication, Type 420 trim packages had not been installed at Unit 2 as e
expected or planned. Review of the work package documentation revealed that f trim packages having all 17-4 PH components were actually installed at Unit 2.
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Subsequently, the licensee performed a safety evaluation that determined that
- trim packages containing 17-4 PH components were approved and acceptable for use.
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2 Was the installation procedure that occurred last year 1
OUESTION 13.
documented, and did it reveal that the old material had been f improperly reinstalled?
ANSWER:
3 The installation of valve internals at Salem Unit 2 in April 1993 was
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documented in the Work Order package, and it revealed that 17-4 PH internals were installed. The Design Change Package called for the installation of a i
420 stainless steel plug with a 316 stainless steel stem and a 420 stainless
- steel cage. '
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00EST10N 14. Your staff indicated in a conference call with my staff that a representative from the manufacturer, Copes-Vulcan, was present at the installation of the material in the Unit 2 PORV's. Did the manufacturer's representative certify in 4
any documentation the content of the material that had been installed, and, if so, what material was described?
1 ANSWER:
The licensee informed the NRC inspectors that no such vendor certification documentation exists or was expected. The Copes-Vulcan representative's
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presence was to assist in the installation. The licensee is responsible for assuring the quality of the installation.
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DVESTION 15.
The NRC indicates in its status report (page 22) that it has concluded that Unit 2 PORVs "are acceptable for continued operation of that unit." Is this conclusion based on assurances from the manufacturer, or on an independent evaluation?
l ANSWER:
This conclusion is based on independent NRC review of the validity of evaluations performed by the licensee and vendor.
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. 00ESTION 16.
While stating that, "each of the licensee's proposals i appears to have merit, the effectiveness of these modifications remains to be demonstrated," the NRC f
concludes, in an apparent contradiction, that the " plant
- design and the procedures that the licensee has (or will have) in place assure that the loss of circulating water to i the main condenser will not challenge the safety of the
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[ nuclear plant."
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If the licensee and/or NRC are not able to provide evidence that the new and proposed modifications will be effective,
, on what assurance is this conclusion of " safety" based?
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ANSWER:
While the
'r These statements do not appear to us to be in contradiction.
t licensee's planned design changes to the circulating water intake structure (relative to modification of the traveling screens to permit higher rotational speeds, trash rake and screen wash pump enhancements, and other possible improvements), may prove more effective relative to handling heavy grass I intrusion conditions, the safety of the nuclear plant is not dependent on the success of these design changes.
The purpose of the circulating water system is to provide cooling for the ma Loss or reduction condenser, a non-nuclear and non-safety related component.
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of circulating water to the main condenser (whether due to grass intrusion, loss of power to the circulating water pumps, or any other condition) could
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OVESTION 16. (Continued) result in turbine trip and possible reactor trip; and might also result in the While loss of the main condenser as an effective heat sink for the turbine such conditions are obviously not desirable, adverse situations involving the effectiveness of the main condenser and the consequent effect on turbine a 1 reactor systems were anticipated, factored into the design of the facility, 1
and are analyzed conditions with acceptable outcomes.
Notwithstanding this demonstrated ability, grass intrusion appears to be developing as a phenomenon that is continuing to impact the normal opera As a result, it is incumbent on the licensee to
- of the Salem facilities. >
1 assess the situation and effect changes, as necessary, to reduce challenges In the short-term, the to, and reliance on, plant design and system function.
licensee has amended its procedures to make it more likely that a turbine t will be initiated if difficulty with the circulating water system is experienced.
In the longer term, if the planned improvements to the V
e, circulating water intake structure prove effective in reducing, if not eliminating, the effects of grass intrusion, even more margin will be gaine Accordingly, it is our intent to closely follow the licensee's efforts to dea with this situation.
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4 . QUESTION 17. Nevertheless, the NRC concludes that the "near-term and 1
- long-term actions initiated by the licensee appear to be sufficient to cause improvement if management maintains their commitment to the program."
Given the history of Salem management failures and PSE&G's repeated promises of improved performance, I am neither comforted nor encouraged by the NRC's unexplained yet enduring confidence in PSE&G's efforts to improve management effectiveness.
I i ANSWER:
(See response to Question I for additional details.) The NRC recognizes that l'icensee management effectiveness is essential to the success of any
) performance improvement endeavor. The results of licensee performance a
improvement efforts may not be immediately apparent. They are expected to be eviden: aM realized in the long-term relative to performance indicators, including: .
1 A. Reduction in:
- 1. automatic scrams (trips) while critical;
- 2. forced outage rate;
- 3. problems associated with personnel errors (operators and others);
- 4. significant events, including occurrences that require AIT
)
involvement;
- 5. inspection findings involving adherence to procedures;
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- 1. .
00ESTION 17. (Continued) i l
- 6. problems associated with maintenance, installation, or
! fabrication; J
- 7. problems associated with design or engineering;
- 8. recurrent violations of a similar nature; and, B. Improvement in overall reliability and capacity for each Salem unit.
l 1
Each of these indicators is being monitored. Our continuing qualified i
!, confidence in the licensee is based on the following:
l
- 1. In 1993, PSE&G acknowledged for the first time weaknesses in management h
effectiveness and the need to achieve performance improvements. -A state of denial existed previously. Thus, PSE&G's acknowledgement of management deficiencies was the first step in correcting problems.
n d The licensee previously recognized the vulnerability of certain aspects l 2.
of tL Silem Crign and processes and took aggressive remedial action.
Specifically, in 1989 PSE&G initiated a program for overall plant
{
revitalization, and was successful in the planning and execution of the j
l effort. Significant material condition improvements were completed (including several design changes and service water system replacement),
measurable improvements were made in material maintenance (e.g., leak reduction, painting, repair of insulation, component labeling, and 1
overall housekeeping), all procedures were reviewed and upgraded, and corrective and planned maintenance backlogs were reduced significantly.
'S J
. i OVESTION 17. (Continued) 3. The NRC staff has reviewed licensee efforts to identify and assess l
i specific areas that require improvement. The NRC staff has also
^ examined their plan for improvement and are satisfied with the scope of the effort. The NRC staff believes that the licensee is committed to carrying out the plan in an aggressive manner. Significant changes in overall leadership, supervision, and organizational structure are l
already evident.
t i
l
- 4. NRC has reviewed PSE&G efforts and progress through inspections and 1
< l meetings with the licensee to keep informed of site activities and b progress toward goals. On the other hand, the staff is aware that many l of these results are in the nature of future promises, not demonstrated improvements, and will require continued close monitoring.
i) 1
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i I e i f
! FOLLOWING ITEMS ARE FROM YOUR LETTER DATED MAY 11. 1994 OUESTION 18. I request that the NRC impose the maximum fine allowable on i PSE&G.
1 i
! ANSWER:
i
] With regard to potential enforcement action related to the Apn17th event, the NRC staff is in the process of reviewing all the facts concerning what happened. It will compare those activities to the requirements of the Code of i Federal Regulations and the license held by PSE&G to determine what violations may have occurred. If appropriate, the NRC staff will call an enforcement
}
conference with the licensee to fully understand their views on what happened i
i and to give them the opportunity to present any facts they consider germane to the issues. Following the enforcement conference, the NRC staff will propose enforcement sanctions if appropriate. This enforcement activity will be y
initiated immediately upon completion of the AIT report.
1 1
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-- . - -. -.. . . - - - - - - - - . - - - .-... ~ ~ . . . - . - - . - . . - - -
00ESTION 19.
The extent of the clogging problems and the adequacy of the current system to handle intake demand and river grass If the system is clogging in the future must be resolved.
deemed incapable of handling the river grass problem, what
( are the technical solutions and when can they be 1 i
i implemented?
4
., 6 l
.. ANSWER. i I
The licensee's short- and long-term actions to cope with the marsh grass and 4
the NRC staff's evaluation of the adequacy of these actions are described in l
- 1 Modification of the
!* Enclosure 2, Item A.9. and in Response to Question 16.
i screens to provide for increased grass elimination is expected to be f
i implemented June 1995 and June 1996, respectively, for Units 1 & 2 at Sale l l This schedule is based on parts availability from the vendor and successful 7
demonstration of the screens to mitigate the impact on fish satisfactorily in A
accordance with the licensee's Environmental Permit.
The service water intakes were not affected by excessive grass intrusion Consequently, the functioning of during or previous to the April 7th event.
L safety-related systems dependent on the service water system have not bee compromised as a result of the grass intrusion problems at the circulating water intake structure.
The Augmented Inspection Team inspected the conditions in the immediate
[ of the service water intakes and determined that the system was not being .
threatened by the grass intrusion in the same manner as the circulating w 4
, . - . . ._ y ,. . . . . . - . , , , .
i . .
k i ; 00ESTION 19. (Continued)
I system, due to relative location, design, and the significantly less water i volume that is required by the system, as compared to the circulating water system. The larger volume drawn into the circulating water system has the f Nonetheless,
- effect of conducting more grass into the pump intake structure.
the NRC staff believes that threat to the non-safety related circulating pump intakes should be ameliorated to reduce unnecessary plant trips and operator l
i challenges.
- 1
- n i
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OUESTION 20. The cause of the safety valve wear must be determined since the reactor core could have overheated if the valves had failed.
MIEB:
Responses to Questions 8 and 10 pertain. Based on the April 7, 1994
' transient, the PORVs functioned as designed while sustaining some wear and galling in the process. However, while proper PORV operation is always preferable for transient control, failure of the valves to function as designed is an anticipated possibility. Accordingly, a redundant and diverse system of block valves is available to isolate the reactor coolant sys' tem if the PORY were to fail open. Overheating of the reactor is not an expected outcome as long as Safety Injection systems are available. The NRC staff will continue to followup on PORV material and design issues to ensure effective generic resolution.
3 4
1 1 -
3
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1
- OUESTION 21. The public needs to know if the NRC can, and will, correct the management and system failures that are real dangers at i
Salem.
ANSWER:
The NRC will take the appropriate actions to ensure the health and safety of the public at the Salem facility. See Response to Question 3.
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ENCLOSURE 2 i
STATUS OF MAJOR ISSUES AFFECTING RESTART ACTIVITIES AT /
SALEM UNIT 1 i
The following issues have been evaluated by NRC staff including (1) assessment of licensee submittals dated April 25, April 29, May 10 and May 13,1994,(2) independent inspection of licensee activities and (3) discussion with 4
- appropriate licensee representatives.
l A. Equipment i
- 1. Pressurizer Power Operated Relief Valve (PORV) Operability ;
Issue:
As a result of the initial safety injection on April 7, the reactor coolant system (RCS) filled with water.
l Without the normal pressurizer steam space to dampen pressure excursions, the continued injection from the first and second automatic safety injection actuations 2
resulted in repeated actuations of the PORVs to limit RCS pressure. As a result of the challenge to the j PORVs, the NRC AIT questioned whether any damage to y the valves had occurred.
a PSE&G Response: The licenset. removed the PORV internals for inspection. The results of the licensee investigation showed that excessive wear was exhibited on the internals of one PORV and slight cracking on the internals of both PORVs. The licensee identified the source.cf the cracking at the boss used for the stem to plug interface in the valves to be intergranular 1- stress corrosion cracking (IGSCC), compounded by the a
stress induced from the different thermal expansion characteristics of the valve internal materials. The cracking occurred where the stem of the valve, which was made of a 300-series stainless steel, was pinned through the boss to the plug of the valve, which was PSE&G replaced made of a 400-series stainless steel.
the internal parts of the Unit 1 pressurizer power-operated relief valves (PORVs), IPR-1 and IPR-2, with
] new internals: a valve stem and plug made of 300-series stainless steel and a valve cage made of 17-4 PH stainless steel. The new stem and plug have essentially the same thermal expansion characteristics, which will relieve the stresses which contributed to the observed cracking. Further, a new design of the valve eliminates the boss used in the previous design and provides a more rigid stem to plug 1
interface. Other factors that promote the IGSCC include the preload stresses that are s99Hed when the valve internaTs are assembTed by the manuf acturer. In fact, similar cracking, though not as prominent, was observed on other valve internals that the licensee maintained as new spares. Consequently, the licensee
. 1 2
i has initiated action to report this apparent equipment '
defect in accordance with 10 CFR 21.
The licensee also modified the procedures used to assemble and install the PORVs in order to prevent potential valve internal misalignment. PSE&G believed the misalignment, which was due to valve installation technique, contributed to the scuffing and galling j
observed on the valve internals after the event. i i
'NRC Followup: The NRC reviewed and discussed with licensee engineering the results of vendor analysis of the affected PORVs. The inspectors subsequently reviewed the PSE&G design change package and accompanying 10CFR50.59 safety evaluation for the installation of the new valve internals. The inspectors determined
' that the new material combination, which has been used in this application before, and the new installation procedure adequately resolve the PORV operability concerns.
- 2. Pressurizer Safety Relief Valves Issue: As a result of the challenge to the PORVs discussed above, the NRC AIT also questioned whether any damage to the safety valves had occurred.
PSE&G Response: PSE&G took steps to assure the operability of the o
pressurizer safety relief valves (IPR-3, IPR-4 and IPR-5). These steps included visual inspection and non-destructive examination of the valves and lift setpoint and seat leakage testing by a vendor, Wyle Laboratories. IPR-3 and IPR-5 tested satisfactorily.
IPR-4 exhibited some seat leakage at 90% of the '
setpoint and lifted at a slightly higher setpoint.
Wyle lightly lapped the seat of the IPR-4, adjusted the setpoint, and the valve retested satisfactorily. ,
l NRC Followup: The NRC discussed the licensee test plan with PSE&G engineering, reviewed the test results achieved by Wyle Labs, and compared the performance of the IPR-3, IPR-4 and IPR-5 with other comparable industry results. The inspectors determined that PSE&G's actions had been appropriate to assure that the pressurizer safety relief valves were operable prior to restart of Unit 1.
i d
4 i
3
- 3. Pressurizer PORV and Safety Relief Valve Piping and Supports l! Issue: Following the Unit 1 trip, the pressurizer filled to a
! water solid condition, which resulted in operation of
- the PORVs and subsequent discharge.of fluid from the The pressurizer to the pressurizer relief tank.
! repeated cycling of the PORVs, and the associated l repeated discharge of fluid, prompted the NRC to question the structural integrity of the effected PORV
- piping and supports.
s.
4 PSE&G Response: To assess the structural integrity of the PORV piping
! and supports, the licensee performed an engineering f
evaluation (S-1-RC-MEE-0898) and several system i walkdowns. .The engineering evaluation referenced
! numerous calculations, assessments, and additional 4
engineering evaluations performed both prior to and l following the event. The licensee's engineering i analysis enveloped the effects on the system caused by the events of April 7. Based on system walkdown l
1, observations, the licensee concluded that there was no
[ observable damage to piping or their supports due to ,
j the repeated discharge of fluid through the PORVs.
i t
NRC Followup: The NRC reviewed the details of the system walkdown, i and the engineering evaluation (S-1-RC-MEE-0898).
l Based on these reviews, the NRC concluded that the
' questions on the structural integrity of the affected PORV piping and supports had been adequately resolved.
!! Steam Flow Transmitter Response to Turbine Trip 4.
[
t Issue:
The initial Solid State Protection System (SSPS) l actuation resulted from the coincidence of low RCS i temperature (due to operator error) and a spurious high steam flow signal. The spurious high steam flow condition coincident with the low primary coolant i temperature. The apparent high steam flow condition ii was previously identified by the licensee, but its ji cause had been attributed to a combination of the SSPS logic (a reactor trip automatically reduces the high steam flow setpoint from 110% to 40% of rated steam l flow) and the actual decay in steam flow following a 4
reactor-turbine trip.
PSE&G Response: Upon closer analysis following the event, PSE&G identified that the actual cause of the indicated high
- steam flow signal following a turbine trip corresponded to the pressure wave initiated by the i closure of the turbine stop valves, that appeared to
' the main steam flow transmitter as a short duration 1
2
4 i
4 high steam flow condition. The licensee subsequently i installed a resistive-capacitive network to decrease l steam flow instrument sensitivity to short-duration steam flow signals, while not preventing the
! instrument from properly sensing a true high steam flow condition.
NRC Followup: The NRC reviewed the licensee modification package and concluded that the transmitter time delay circuit is an appropriate means of resolving the spurious steam signal phenomenon without compromising the safety function of the steam flow transmitter.
- 5. Steam Flow Instrument Drift Issue: Steam flow instrument calibration at Salem station has been known to change with time [ drift] since initial plant operation. As a result, indicated steam flow, for the same power level, increases with time at power and decreases with time after a plant trip or
- shutdown. Periodic re-calibration had been required to make indicated steam flow equal 100% at 100% power.
This phenomenon had caused, along with process noise, spurious frequent tripping of steam flow bistables and J logic input relays. Although this phenomena did not appear to play a direct role in the event, probably due to recent Unit 1 modifications, the historic frequent tripping of the bistable may have contributed ,
to premature deterioration of the safety injection
) logic relays and the different responses of the safety ;
i injecticn logic experienced during the event. l PSE&G Response: The licensee stated that the cause of the instrument drift was entrained gases in sensing lines leading to the instruments, which has been supported by two l consultants. In order to correct this problem they have replaced the instrument sensing lines with larger tubing, larger condensing pots, reoriented the lines j to a consistent downward slope and have removed insulation from sensing lines and condensing pots to promote condensation and facilitate escape of noncondensible gasses. This modification was installed in Unit 1 last outage [Nov '93-Feb '94] and will be ins ~talled at Unit 2 the next outage (Oct '94].
Results from operation at Unit I since startup have been inconclusive. Since the unit has not been '
maintained at full power in any period sufficient to verify the effectiveness of the modifications.
However, no re-calibrations have been required since the modification was installed. Additional plant operating time at full power will be needed to a
1
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! determine if the modification has been effective in reducing or eliminating the " drift". l
} i The licensee has a surveillance procedure in place to
- 1 -
monitor steam flow instrument calibration at both l l units. The procedure includes acceptance criteria for 1
identifying unacceptable drift. The procedure identifies when recalibration should be accomplished.
Addition of the resistive-capacitive network to l resolve the reaction to short duration pressure pulses ,
j3 will also reduce the sensitivity to process noise l
- i. signals as discussed in item 4 above.
) -
8 Licensee calculations show that calibration 4' adjustments have not violated any technical specification requirements.
The licensee acknowledges the frequent tripping of the i .
bistables, but believes there is insufficient data to
!y support a cause/effect relationship between spurious
- . frequent tripping (chatter) of logic relays and the 1
difference in the logic trains' response during the
! event.
NRC Followup: NRC staff has reviewed the licensee response to T. T.
j Martin dated May 13, 1994 concerning steam flow instrument drift. The letter includes details on the licensee monitoring program and associated calibration h adjustments made to ensure steam flow set point values i remain within technical specification required values.
4 The NRC staff concluded that the steam flow instrument l drift should be minimized by the condensing pot and 4
sensing line modifications installed at unit I and i planned for unit 2. The procedure for monitoring steam j l flow instrument calibration has been reviewed and l found to be acceptable.
l]
There is not a preponderance of evidence to prove that l there is a nexus between steam flow. instrument drift i
and associated input relay chatter and apparent differences in steam flow safety injection logic
- relays. The NRC staff has also concluded that the l
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different responses of the 'A' and 'B' safety injection logic relays are explainable as normal variations in time response of these relays.
4 Installation of a resistance-capacitance circuit in ,
i the steam flow instrument measuring circuit should minimize the steam flow instrument's sensitivity to short duration steam pressure pulses as well as l i
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process noise. This circuit will not degrade the response of the instrumentation to accident l:
conditions.
Based on the licensee monitoring program in place to ensure instrument drift does not result in the violation of technical specification limits, the j
safety function of the instrumentation will be assured.
i
- 6. Solid State Protection System /High Steam Flow Input Relays Issue: Following the reactor trip and initial automatic
- safety injection (SI) of April 7, operators recognized i
that only train A of the solid state protection system (SSPS) had actuated. Several actions controlled by l SSPS train A failed to go to completion resulting in l several components not operating as expected. The
{
apparent disagreement between the SI logic trains was not provided for in the E0Ps, and operator re:;pnse to the event was delayed as they manually aligned the two h'
trains and the affected components.
i' PSE&G Response: Due to the different responses of train A and train B
- of the solid state protection system (SSPS) to the i
event, PSE&G conducted further examination and testing
! of SSPS components. -The licensee concluded that the very short duration of the high steam flow signal explained why only train A of SSPS initiated. Al so ,
- the various components within a SSPS train are h
' operated by different latching and seal-in relays, that also have different response times. This fact, i
along with the short duration high steam flow signal, i
explains why not all actions of train A (main steam and feedwater isolation) went to completion. While l the licensee testing showed a difference between the i
time response of the two SSPS trains and found l
r discoloration in some SSPS relays, the licensee determined that both channels operated within the SSPS
.jje design and Technical Specification requirements.
Further testing results confirmed that had an accident condition existed, both SSPS trains would have actuated and all actions would have gone to completion. The licensee nonetheless replaced the l high steam flow impact relays, and subsequent testing l showed the differences between the channel time i
22
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a i
responses had been reduced. PSE&G provided additional
- guidance to plant operators on manual actions to be taken in the event of different responses of the two l- trains of SSPS.
i 1
NRC Followup: The NRC staff monitored the licensee investigation, reviewed the initial test data, and observed portions of the licensee follow-up testing of the SSPS relays. l i
- The inspectors determined that.the licensee's root 1
} cause was acceptable. The staff also determined that i the replacement of certain relays was prudent, and that the guidance provided to the operators was (l
i appropriate.
i*
- 7. Main Steam Atmospheric Relief Valve (MS 10) Controller j
The MS-10s did not ' automatically respond to and
! Issue: control high steam generator pics wre en April 7
! 1994. Following the plant trip and initial safety j ' injection, the reactor coolant system (RCS) i temperature increased as a result of core decay heat
!] and reactor coolant pump heat. This RCS heatup, and the corresponding increase in steam generator pressures, was not recognized by the Salem operators.
Steam generator pressures increased above the setpoint of the atmospheric relief valves, because of a failure l of the MS-10 controllers to promptly respond. i Consequently, the steam generator code safety valve lifted; The steam release through the safety valveThe l I
3 caused a cooldown of the reactor coolant system.
l j cooldown of the RCS resulted in a rapid pressure j decrease that initiated the second automatic safety injection due to an actual low pressurizer pressure condition.
j PSE&G Response: During normal plant operation the MS-10 controllers '
, provide a constant close signal to the valves since normal steam pressure is much lower than the valve opening setpoint. This results in the saturation of I the controller circuitry. As a result, the automatir.
opening of the valves is delayed during actual !
conditions of high steam generator pressure by an I amount of time it takes to clear the saturated condition. The controller was modified shortly after initial startup of the Salem unit to prevent inadvertent opening of MS-10. PSE&G has now implemented a design change to install a discharge 1, path for the capacitor in the control circuit which This 4 was susceptible to the saturation phenomenon.
design change re-installed,the part of the circuit which the licensee had previously removed. The controller gain and reset times have also been changed
,w
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g i i
8 to further improve the controller time response to a I rapidly increasing steam generator pressure condition h and avoid inadvertent openings of MS-10 valves.
NRC Followup: The NRC reviewed the design change package which implemented the changes in the MS-10 controller
- . circuit, discussed the modification with licensee
! engineering, and concluded that the re-installation of
! the capacitor discharge path would provide better automatic control of steam generator pressure during trarsient plant conditions. The' inspectors will
!j _ observe licensee testing of this modification during
- i
' plant heat-up.
1 l 8. Rod Control System Operation Issue: The rod control system was being operated in the manual mode due to ongoing system troubleshooting and operator uncertainty with regard to the system operability in the automatic mode. If the system had i
e been operated in the automatic mode the excessive reactor coolant system cooldown may have been minimized or avoided.
PSE&G Response: At the time of the event, the rod control system deficiencies had been resolved with the exception of monitoring a system isolator to determine if a drifting problem had been corrected. Final system testing was scheduled the day of the event. Following 7 the event troubleshooting determined that the i
automatic mode was fully operable.
NRC Followup: The AIT reviewed the results of the troubleshooting and testing of the rod control system and determined that PSE&G had adequately corrected the system deficiencies to permit operation of the rod control system in the automatic mode.
I 9. Circulating Water Intake Issue: Marsh grass accumulates in the Delaware River and is drawn into the circulating water system by the circulating water pumps. When the grass quantities become large they tax the traveling screens' ability to remove the grass as fast as it accumulates, clogs the intake flow path and causes loss of cooling to the main condenser. Loss of cooling to the condenser
[ requires reduciion of plant load, or plant shutdown.
PSE&G Response: The licensee response is divided into short and long term actions. In the short term the licensee has I
'l
/ i l
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9 l -
e assigned maintenance and operations personnel to the l circulating water intake structure to maintain and i
clean the screens. Prior to the last refueling outage
! the licensee installed low pressure headers to clear j
siltation and improve screen wash spray nozzle effectiveness.. Screen wash control panels and
- instrumentation were replaced or refurbished.
i Procedural enhancements have been made since the event to give operators more guidance on responses to an i
influx of marsh grass. Criteria for initiating a
- manual reactor and/or turbine trip have been included.
i The density of grass loading is currently showing a
!. decreasing trend. The major impact of marsh grass is 4
expected to be over for 1994.
i Long term enhancements include modifications to the
! traveling screens to permit higher speeds. The higher
- j. screen speed will increase the grass removal j capability of the screens and lessen the probability
- of loss of circulating water flow due to grass h intrusion. Higher speeds will be achieved by ji replacing the screen baskets with lighter material and
- replacing the drive motors / gearing and controls for
{ higher speeds. These modifications are expected to be j completed by June 1995 for one Salem unit and.by June 1996 for the other unit.
2 In addition, the existing trash rakes, which are j positioned in front of the screens will be replaced to j1 enhance trash rack cleaning and levelize intake 21 velocity profiles. This modification is expected to be j completed in October 1994.
! The licensee plans to replace two screen wash pumps l [there are 4 per unit] with pumps of upgraded The ,
- materials and lower maintenance requirements. I licensee then intends to evaluate the screen wash !
system to determine optimal pump operating range, and ;
] to monitor the system effectiveness. This modification i is expected to be completed in October 1994. Pending the results of the experience with these two pumps, the remaining 6 pumps may be replaced with the new design.
i PSE&G plans to make other modifications, including spray nozzle additions and re-orientations, internal piping modifications and new designed seals between
) stationary and moving screen components to improve grass handling capabilities. The implementation schedule for these modifications has nat been established.
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h-10 The licensee is also reviewing the circulating water system, the grass movements and loadings, and will consider various approaches, such as physical barriers
} in the river to improve the ability to mitigate marsh grass and removal of grass by dredging. No schedule for completion of these studies has been provided.
NRC Followup: Long and short term plans for coping with the grass problem have been reviewed by the staff and discussed with the licensee. Long term plans appear to be aimed at coping with potentially severe grass intrusions.
Each of the licensee's proposals appears to have
- merit. The effectiveness of these modifications remain te be shown through experience in the future.
Operators have been trained to deal effectively with severe intrusions of marsh grass. In addition,
~
procedures have been revised and equipment has been modified to address grass intrusion. a The NRC has reviewed the licensee's procedures and
] training of operators for coping with grass intrusions. Evaluation of these procedures is discussed in Sections B.2 and 3 below. The plant has been designed and the procedures that the licensee has put in place will accommodate loss of circulating water to the main condenser, regardless of cause.
B. Procedure Improvements 1
- 1. SC.0P-DD.ZZ-0022(Z), " Control Room Reading Sheet Mode 5 Through 6" Issue: Following the plant cooldown subsequent to the April 7 ;
events, the NRC identified the Salem Unit I reactor vessel level indication system (RVLIS) indicated reactor vessel water level at 93%. When questioned, the Salem control room operators could not explain the a
significance of the indication, nor were they required to monitor this indication in the current plant 1
operating mode.
)
PSE&G Response: RVLIS values are now logged when a unit is in Mode 5 j (Cold Shutdown) or Mode 6 (Refueling), and the procedure requires response actions when the indicated l level is below the minimum value specified in the procedure.
i NRC Followup: The NRC staff reviewed the procedure change, discussed the change with Operations management, interviewed operators to assess their knowledge of the new requirements, and observed operator training in the
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11 The inspectors concluded this action Salem simulator.
addressed the NRC-identified deficiency in Salem control room operator use and application of RVLIS indication when the plant is in Mode 5 or 6.
- 2. 51(2),0p-AB.COND-0001(Q), " Loss of Condenser Vacuum" During the rapid downpower concucted by Salem Unit I Issue: operators immediately preceding the April 7 reactor trip, the operators took extraordinary steps toattem the loss of circulating water pumps and main condenser cooling. The NRC determined that a lack of procedural y
guidance existed for operators on when to trip the turbine and/or reactor during 1cw power operation.
PSE&G Response: The procedure now specifies actions to trip therea primary coolant temperature, condenser vacuum, cond
, power conditions.
HRC reviewed the procedure change and noted that the NRC Followup:
specific guidance provided in the procedure now adequately directs operators on what the necessary plant conditions are to remove certain components from The inspectors confirmed operator awareness service.
of the new requirements through operator interviews and through observation of simulator training on the
, new procedure.
i 3.
S!(2).0P-;,9.CW-0001(Q), " Circulating Water System Malfunction" Sl!2).0P-SO.CW-0001(Z), " Circulating Water Pump Operation" The rapid downpower maneuver performed by Salem Unit 1 Issue:
operators on April 7 was necessitated by the r grass accumulation and the resultant loss of main condenser cooling. The NRC determined that the y
operators lacked procedural guidance on wh river grass on circulating water pumps.
These procedures now specify operator actions for the PSE&G Response: condition when two or more circulating water pumps are out of service and identify actions for operators to take in the. case of abnormal condenser vacuum
} situations.
12 i
NRC Followup: The NRC reviewed the procedure change and operator '
knowledge of the new instructions and observed their practice in the Salem simulator. The inspectors determined that the new procedures provide the proptr guidance to the plant operators for the loss of l circulating water pumps. :
- 4. Sl(2).0P-AB.TRB-0001(Q), " Turbine Trip Below P-9" s
Issue: During the April 7 downpower maneuver, Salem operators reduced reactor and turbine power at different rates. !
' The resulting power mismatch resulted in the ,
- overcooling of the primary coolant system and the subsequent need for the operator to withdraw control rods, which led to the reactor trip. The operators did not have guidance to manually trip the turbine off-line to restore primary coolant temperature.
PSE&G Response: The turbine trip procedure now incorporates guidance for operator response to inadvertent or excessive primary coolant cooldown conditions. The new guidance
} provides for manually tripping the turbine under 1 certain conditions in order to prev.nt unnecessary '
challenges to the reactor and primary coolant system.
NRC Followup: The NRC reviewed the procedure change and noted that the guidance for operator action relative to a manual l trip of the turbine was appropriate and properly .,
addressed the concerns of the event. The inspectors subsequently verified, through interviews, adequate
}' operator knowledge of the new guidance and observed satisfactory performance of the new procedure at the Salem simulator. .
- 5. Sl(2).0P-IO.ZZ-0004(Q),"PowerOperation" Issue: The power mismatch between the Salem Unit I reactor and turbine which occurred on April 7 resulted in the l overcooling of the primary coolant system to the point where coolant temperature went below the minimum temperature for :riticality as specified in the unit Technical Specifications. The operators-did not have <
adequate procedure guidance for required action when plant operation did not meet the Technical Specificatior requirement for minimum temperature for ,
criticality. l l
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I 13 PSE&G Response: The procedure for power operation of the Salem units now has specific directions for maintaining reactor i coolant temperature greater than, or equal to, the l minimum temperature for criticality. If this temperature cannot be maintained above the' minimum temperature for criticality, operators are required to trip the reactor.
NRC Followup: The NRC reviewed the new guidance and specific direction provided in the procedure change for maintaining primary coolant temperature above the i .;
Technical Specification limit. The inspectors conducted operator interviews and observed operator simulator training and concluded that the procedure j change and operator training adequately addressed the 4
F issue.
- 6. Emergency Operating Procedures (EOPs) f Issue: During the operator response to the reactor trip and i multiple safety injections on April 7, the operators encountered situr.tions where the E0Ps did not provide specific guidance or direction. These situations included:
- Resolution of solid state protection system logic train disagreement,
- Manual operation of the steam generator 1 atmospheric relief valves to control steam 4
generator pressure and primary coolant system (RCS) heatup, and
- Prevention of solid RCS conditions and, if they do occur, a plant cooldown under those conditions.
PSE&G Response: PSE&G is pursuing long term changes affecting the E0Ps
{ and Critical Safety Function Status Trees (CSFSTs),
working in conjunction with the Westinghouse Owners Group. In the interim, the licensee has provided additional guidance concerning these situations to operators in an Operations Department Information Directive (ID) and in a simulator training lesson plan In response which addresses the entire April 7 event.
to the above situations, the ID provides guidance to operators on: when a safety injection train
.[~ disagreement is noted, to manually initiate a safety injection actuation for the train that did not automatically actuate; following a reactor trip, to take manual control of the MS-10s at any time steam
14 generator pressure is at or above the valve setpoint with no apparent valve motion; and, during E0P use g after initiation of CSFSTs, and if no higher path j' conditions exist, the Shift Technical Advisor is to refer to Yellow Path Restoration Procedures to monitor RCS parameters and other indications in order to detect or prevent unexpected plant conditions, such as solid RCS conditions. Reading, discussing and understanding the ID, and instruction in the simulator lesson plan, were required of all licensed and non-licensed operators prior to their assuming a watch.
NRC Followup: The NRC discussed the considered E0P changes with Salem Operations Department management, reviewed the guidance provided in the department's ID and the simulator training lesson plan, and observed the training of operators using the lesson plan at the simulator. The inspectors verified operator knowledge of the new guidance through interviews of several operators from different shift crews. The inspectors y concluded that the guidance provided in the ID and the training provided at the simulator were an effective means of resolving the evidenced E0P concerns.
C. Salem Operating Crew Shift Composition and Shift Management Responsibilities Issue: In addition to the above identified equipment and procedure issues, the NRC identified several areas in
- which Salem control room operator performance and j resource management affected the response to the event. These areas included
- Maintaining adequate control room staffing,
- Control room crew communications,
- Prioritization of personnel assignments 2 and use of additional licensed operating personnel, and
- Scope of Senior Nuclear Shift Supervisor involvement in Emergency Operating Procedure (EOP) operations.
PSE&G Response: PSE&G determined their operational experience
{ established a level of confidence in the ability of the presently reqMred shift crew to successfully operate the Salerr ;acility. The licensee, however, also identified a number of root causes and causal
' t.1
15 factors for the event that were associated with resource utilizatien, encompassing the above areas identified by the NRC.
The licensee responded to the identified concerns through the previously noted Salem Operations Department Information Directive (ID) and simulator training. All Operations crew shifts received the simulator training on the lesson plan derived from the event, and all shifts were required to read, discuss and understand the directions provided in ID prior to resuming a watch position.
NRC Followup: The NRC reviewed and inspected the above procedure changes and training enhancements. The review included interviews with licensed operators, discussions with Operations Management, and observation of crew training at the Salem simulator.
The inspectors concluded that the changes made to the noted procedures, the additional training supplied to 1
licensed operators, and the guidance provided by management to the operators effectively addressed the personnel performance issues identified as a result of the event.
D. Unit 2 Consideration Considering the procedure changes, training and Issue:
hardware modifications identified from the event for !
implementation at Unit 1, the NRC was questioned what short and long term corrective actions were being implemented at Unit 2.
PSE&G Response:
As a result of the event at Salem Unit 1, operator I retraining and procedural enhancements were implemented at Unit I and 2. Design modifications were performed at Unit I and are planned for Unit 2 no later than the next refueling outage, that begins 1 October 15, 1994.
Operators were given additional training and written guidance on response to marsh grass, downpower and low power operations, RCS temperature control, control room resource management and proper actions to be taken for solid state protection system train disagreement. Operators have been trained, prior to g this event, on how to cope with MS-10 controller L malfunctions and how to operate the system in manual.
They were given additional training following the event.
The Unit 2 PORV internals are of a different material, The 17-4 PH stainless steel, than those at Unit 1.
17-4 PH internals are approved for this use by the
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vendor and are similar to those which were installed
! in both Unit I and Unit 2 at the time of initial operation. Finally, the licensee has not experienced l any problems with this material to date, and believes
!' continued use until the next refueling outage is justified.
l The licensee believes that delaying implementation of l- the hardware fixes to an outage of sufficient duration, but not later than the next refueling i outage, currently scheduled for October 15, 1994, is j
4.
appropriate.
t NRC Followup: The NRC reviewed the 10CFR50.59 safety evaluation for
! continued operation with the Unit 2 PORVs in the as-is 1
condition. The NRC verified that the internals of the
- Unit 2 PORVs were replaced with components made from l 17-4 PH stainless steel. In addition, the NRC l confirmed that the material changes for the internals i
were approved by the<PORV vendor. The PORVs will be
- i . inspected and a design change considered during the
!. next refueling outage. The inspectors concluded that l
4 '
the Unit 2 PORVs are acceptable for continued l
operation of that unit.
The NRC staff has reviewed the planned modifications (MS-10 control circuit and steam flow circuit time delay) at Unit 2 and concluded that compensatory measures provided by improved procedures and operator 1
training are acceptable until the next outage of ,
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sufficient duration to install the modifications.
What is our opinion of the need for the other hardware )
changes?
The inspectors have reviewed procedures and training related to coping with rapid power reductions, use of reactor vessel level instrumentation, manual veration J of MS-los, RCS temperature control, logic tra m disagreement, control of noncondensible gasses in the vessel and cooldown of a solid RCS. With these procedures in place and the associated training completed, operation of Unit 2 until October 15, 1994 is considered acceptable.
E. Management Effectiveness in Resolving Long-Standing Problems Affecting
[ Performance at Salem Since the November 1991 Turbine-Generator failure Issue: event, which resulted in review by an Augmented Inspection Team, PSE&G has continued to experience
d 0
- 17 recurring operational, design, and maintenance-related ,
problems . Contributing causes to these occurrences I
have been weaknesses in management and oversight of-
' activities, inadequate root cause analysis, failure to follow procedures, personnel error, ineffective approach to resolution of problems, and insufficient corrective actions. While none of the events have adversely affected public health and ssfety, the licensee's apparent inability to, demonstrate improving performance has been a continuing concern to the NRC.
PSE&G Response:- In their May 13, 1993, letter, PSE&G noted that they
- have established plans and completed actions relative to: (1) Salem Performance Improvement; (2) Quality Assurance / Nuclear Safety Review Oversight; and (3)
Augmented Independent Oversight.
Prior to the event PSE&G management had already implemented significant material conditions upgrades -
at Salem, including design changes that directly improved control room operations. Additionally, a l
! Procedural Upgrade Program was completed in 1993.
While improving performance, as indicated by reduced numbers of events caused by personnel error, the ,
licensee recognized that satisfactory performance was ;
-not yet achieved. Consequently, the licensea l commissioned a special Comprehensive Assessment of Performance Team (CPAT) in the summer of 1993 to '
review and assess PSE&G's performance as indicated by
) the assessment of several deficient conditions and 3 situations over the last few years. The CPAT activities are now completed and the results have been factored into the Nuclear Department Implementation Plan (Plan). The Plan identifies the program for implementing a comprehensive series of measures designed to effect and assure performance improvement.
Actions were also taken prior to the event relative to J leadership improvement, including organizational :
l structure changes, reconstitution of the organization with more capable supervisors, and established requirements for increased supervisory oversight ~
activities in the plant. An additional operating i l
engineer has been assigned to provide in-field '
oversight and direct monitoring of the performance of supervisory personnel until all management enhancements are in place.
The management of Quality Assurance and Nuclear Safety Review Oversight Groups has recently been changed to :
improve oversight effectiveness. Other personnel supervisory changes have been accomplished to effect 4
e
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18 1
4 better overall performance. An independent consultant j) has provided an evaluation to assure the selection of l 4
properly qualified personnel for this area. Enhanced f
procedures and policies for safety reviews, audits, assessments, and communications of. findings were j
established prior to the event.
l Subsequent to the event and until the results of the
' CPAT effort are established and the planned enhancements in organization, personnel, and policy are completed, an Augmented Independent Oversight l, group has been selected to maintain full oversight l p coverage on all shifts, 7 days per week. The group i
" l has been directed to monitor activities such as reactor startups and shutdowns, low power operations, l
i special tests and surveillances, major system and maintenance evolutions, work control performance and ,
i l control room conduct, and shift turn-overs and planning meetings. The individuals will provide daily l
- feedback to the Manager of Nuclear Safety Review, and weekly feedback to the Vice President and Chief if Nuclear Officer. The' Augmented Independent Oversight l' coverage will be maintained until significant l j improvement are noted in station performance and in the quality of the Nuclear Safety Review function. ,
i 1
Finally, the licensee has expressed confidence that
- these structural and personnel changes will provide j
the impetus and management attention necessary for
!) significant and lasting improvement.
j; NRC Followup: Previously, the NRC has reviewed and assessed the i licensee's CPAT effort. The CPAT was thorough and i developed a comprehensive list of problems and
( weaknesses that appear to be causal to the recurrent
! failures noted in the licensee's performance. The NRC i
has also reviewed the Nuclear Department Tactical Plan which identifies the action and performance schedule to resolve each generic problem or weakness 1 identified. The plan is very aggressive and thorough in the approach to resolution of the weaknesses. The schedule, while extending into 1995 for some of the more difficult matters to resolve, appears timely in view of the scope of the effort. NRC has already noted aggressive action to re-evaluate the quality and performance of managers and supervisors in the Salem organization. Several replacements have already occurred, including the replacement of the previous 1 General Manager-Salem Operations with the current Vice l Pre'sident-Operations for PSE&G.
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19 NRC has reviewed the credentials of the individuals assigned to the Augmented Independent Oversight group.
t i
.Their background, experience, and ability seem to be appropriate for the task at hand. . It is the expectation that the group will be successful in its endeavor to monitor the quality of performance and provide the necessary feedback to the right level of management to assure effectiveness and management cognizance of the quality of operations.
While a positive trend has not yet been demonstrated in Salem performance, the near-term and long-term actions initiated by the licensee appear to be sufficient to cause improvement if management maintains their commitment to the program.
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- WASHINGTON, DC 20610 0802 May 18,1994 5
j Mr. Ivan Selin F- Chairman-U.S. Nuclear Regulatory Commission '
1 Washington, D.C. 20555 Dear Chairman Selin; I am deeply disappointed by the Nuclear Regulatory Commission's i
- response to my correspondence of May 11,1994 and its subsequent Given the decision to allow the Salem I nuclear facility to restart.
history of problems at Salem, the NRC has a public responsibility to warrant with as" much certainty as possible that operational and management deficiencies of the past have been corrected.
in ,your staff's, response to my letter, in whict),I asked for a tho
] review of a number of, issues relating to plant operations, your staff states that "the NRC has reviewed all the relevant restarttheissues, However, letter and is satisfied that they have been adequately addressed."
fails, in my view, to' provide assurance on the critical restart issue: Ca the licensee prove'that it can and will operate th6' plant any differently the future than it has in the past?
I Instead of addressing each of the concems clearly spelled out in my letter to you, your staff enclosed the NRC analysis (status report) of PSE&G responses to issues raised by the NRC. While the docume offers some insight into Salem's operations, it does not provide any statement of conclusions or analysis upon which a restart decision rest. Notably, the licensee's full submittal was receivedGivan by your the offic the NRC's analysis was completed that same day.
[ May .13,1994; short time frame for review, i question the degree of confidence that could have gained in PSE&G's ability, or even intention, to correct operational problems at the Salem I facility.
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i Mr. Ivan Selin
! 5/18/94 1
A major deficiency of your letter is that it does not assure m l the NRC..will take any responsibility in the event that Salem en l
i future problems, nor does it make In a letter any to commitments me dated May 12,for strong a l intervention if such problems occur.:1992, responding to m following an incident with the turbine generators at Salem in 19
! stated, "While the NRC is satisfied at this l prevent events of similar. nature, the NRC will monitor th j
efforts closely and will not hesitate to take any furtherIt action has appropriate to effect necessary changes in operations or a l ',
been two years, and little has changed, in the way of improved l performance, at Salem.
i l After aEthorough review of the documentation you enclosed w i your letter, a number of the major concerns outilned in m j
persist.
I am requesting.,a specific response to each of the followin l, - ..
questions.
- i '
l The first issue concerns the , pressurizer power operated valves (PORV), their reliability and problems associated My with installati'o'n last ye(r "of. 'new interrials in the valves'in Unit staff has reviewed this issue with 'the NRC staff,'but funda questions remain.
y Specifically, why did the manufacturer recommend What old material (17-4 pH) that had been used since the early its 1 testing reliability?
had been performed on the new m ;
NRC database on equipment defects, requiredPORVs to be re l
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with 10 CFR 12, reviewed for reports of simila in other . reactors? is this new material now in the PORV been notified of the.S,alem damage?Will the NRC, or m ill be l regarded as inferior to the old material? direct o
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Page 3 j
Mr. Ivan Selin jll 5/18/94 i
l PSE&G indicated that valve internal recommended for installation?
l misalignment may have contributed to the failure o,f the valve l the Status Report).; Was the valve installation technique a prob l on manufacturer installation specifications or inadequate licen i And what is being done to correct installation control procedures?
l- problems?
l Regarding the PORVs in Was Unitthis 2, awhen was the NRC notified t result of operator l wrong material had been installed?
j notification or a result of my office contacting the NRC with this j Was the installation procedure that occurred last year information?
!t documented, and did it reveal that the old material had been imp l' installed?
Your staff indicated in a conference call with my staff that a i
j representative from the manufacturer, Did Copes-Vulcan, the manufacturer'swas pre installation of the material in the Unit 2 PORVs.
l represen,tative certify in any documentation theThe content NRC of t l that had .been installed, and, If so,-what material was described?
l mdicates. in its status-rep' ort.(page.22) that it has., is this concluded l'* PORVs "are acceptable for continu~ed operation of that unit."
l conclusion based on assurances from the manufacturer, or on an l .'
independent evaluation? - -
l The second issue concems the problem of rharsh grasses clo the circulating water intake flow path, which was the catalyst fo series of failures that led to the April 7th shutdown.
l]
j The licensee provided theHowever, NRC with a number of short and lo most of the modifications l solutions to this problem (page g). in fact, an implementation cited by PSE&G have yet to be implemented, i
schedule has not even been established for some of th While stating that, modifications.
- ) appears to havethe merit, the effectiveness of these modif NRC concludes, in an apparent contradiction.
l to be demonstrated," ill l that the " plant design and the procedures that the license l
have) in place assure that the loss of circulating water to 1
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Page 4 l
Mr. Ivan Selin 3
5/18/94 f
i l If the f condensar. will not challenge the safety of l proposed modifications will be effective, on what' assura
] conclusion of " safety"' based?
l' The third and most serious issue is management As ineffectiv l resolving long standing problems affecting facility performance.
7 recently as March of.this year, PSE&G was fined $50,000 for
- violations. blamed on continued weaknes l5 dozens of viola,tions.
l I The NRC' (page.18) cites several factors that have Those contr f
l recurring operations design and maintena l l
- . inadequate root cause analysis, failure to l[ il l corrective actions? PSEE&G has made j Clearly, the efforts have not been adequate. PSE&G h 7th incident.
promised' additional.. changes to irhdrove managem even the NRC acknowledges that a ' positive trend $is n demonstrated in Salem's performance.
I that the "near-termGiven "
and long-term actio the history of Salem their commitment to the program.
management failures and PSE&G's r unexplained yet enduring confidence in PSE&G efforts to im management effectiveness.
{ Mr. Chairman, the public is entitled to definitive the long an y least all aspects of Salem's operations, inclu
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- 23,15,u m it aas stLes wim - ;cissieT2 i
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i Mr. Ivan Selin J 5/18/94 i
-- Increased scrutiny by the NRC in reevaluating the decision to grant l
permission for a restart,.is not only merited, but required under the i Commission's public responsibility and trust. -
S. - . .
p Sin erely, j' - '
/
- 6E t l -
Joseph R. Biden, Jr.
l - .
United States Senator l
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