IR 05000298/1995004
| ML20217G128 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 10/03/1995 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20217F876 | List:
|
| References | |
| FOIA-97-148 50-298-95-04, 50-298-95-4, NUDOCS 9708070100 | |
| Download: ML20217G128 (114) | |
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COOPER NUCLEAR STATION SPPR 95 04 SUMMARY OCTOBER 3. 1995 SALP CYCLE 013 (JULY 9. 1995 THROUGH JANUARY 11. 1997)
1.
OVERVIEW 0F PERFORMANCE A.
PERFORMANCE WAS ASSESSED AS THE COMPLETION OF THE SALP CYCLE (JULY 8. 1995).
THE OBSERVATIONS IDENTIFIED IN THE SALP REPORT (DATED AUGUST 2. 1995) HAVE NOT SIGNIFICANTLY CHANGED.
Has operated at 100 percent power since Februar 27, 1995,
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without any significant incidents or problems. y Challenges still remain regarding improvement in overall
performance level, such as:
performance of the engineering organizations.
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increase the staff's aggressiveness for the
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identification and resolution of deficiencies increase the intrusiveness of the 0A department during
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performance of audits.
Licensee effectively resolved the issues related to the
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performance of the Stati u Operations Review Committee, The licensee has formulated a comprehensive plan to improve
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performance.
0/erall performance remains.at about the same level as was
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noted during the previous SALP assessment (8/2/95),
B.
HANAGEMENT CHANGE Bill-Mayben, formerly CEO of R. W. Beck, was appointed as e
the new CEO and President Mike Peckham was appointed as the Senior Manager Site
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Support Rick Gardner, formerly Maintenance Manager was appointed as
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the Operations Manager Jack Dillich is the new Maintenance Manager e
7Jeo g y 970805 g
MATTHEW 97-148 PDR u
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e Paul DiRito, formerly Operations Manager is now working as l
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a Senior Engineer Phil Graham, formerly of Entergy is the new Senior
Engineering Manager Mike Hale is the new RP Manager
Brad Houston, formerly of Brunswick Nuclear Plant, is the e
new EP Manager II.
SALP FUNCTIONAL AREAS A.
PLANT OPERATIONS 1.
PERFORMANCE Good since the )lant was restarted in February 1995, from e
the prolonged slutdown of 9 months.
Rated 2 in this function area in the last SALP (8/2/95)
Management oversight of the activities performed by
operations personnel outside the control room has not been effective.
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Lack of the identification of deficiencies
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Failure to follow procedures Some performance concerns have been observed with the
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Operations Department. in providing support for the maintenance staff in the performance of maintenance and surveillance.
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Failure to follow procedures
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Lau of plant status awareness.
2.
PERFORMANCE BASIS A new Operations Manager was recently assigned in order to
improve resolution of issues identified in the SAlP report.
This appointment was recent and the results of this management change has not yet been observed.
3.
PERFORMANCE TREND / ROOT CAUSE The performance trend in this area appears to be consistent
with the last SALP rating of 2.
4.
PERFORMANCE INFORMATION GAPS:
None
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liAINTENANG1 1.
PERFORMANCE Performance in this functional areas was rated as 3 in the e
last SALP (8/2/95).
A continuing issue identified previously and reiterated in
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the last SALP is the licensee's over reliance on the skill of the craf t.
Recent improvement was noted when Rick Gardener was serving
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as the Maintenance Manager.
Mr. Gardner was recently replaced by Jack Dillich and additional evaluations will be required to determine if improvement will continue.
As discussed above, some performance concerns in this
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functional area are a result of poor support from Operations in the performance of maintenance and surveillance.
2.
PERFORMANCE BASIS The overall performance level in this area appears to be consistent with the previous SALP rating of 3.
This conclusion is based on the fact that it does not appear that the licensee has taken any effective actions to address the performance deficiencies identified in the SALP report.
3.
PERFORMANCE TREND / ROOT CAUSE The performance in this area remains as previously identified in the SALP report.
4.
PERFORMANCE INFORMATION GAPS:
None C.
ENGINEERINS 1.
PERFORMANCE Performance in this functional areas was rated as 3 in the
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last SALP (8/2/95).
Poor performance of the engineering staff has been a concern
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for quite some time and remains the area of most concern, especially system engineering.
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Weak management oversight of the engineering programs Fragmented ap3 roach to resolution of problems caused.
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in part, by t1e remote location of the design engineering staff.
Failure of the system engineers to perform an adequate
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level of oversight of their assigned systems
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Lack of the identification of system deficiencies The licensee has addressed the remote location aspects of
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the engineering organization by relocating all engineering functions at the site.
To address the concern regarding the weak oversight of the
3erformance of the engineering organizations, the licensee lired a new managers and completed a reorganization of the engineering department.
2.
PERFORMANCE BASIS Lack of oversight by engineering management has resulted in e
the engineering staff not being arovided with a definite set of expectations As a result, t1e performance of the engineering staff has not been effective.
3.
PERFORHANCE TREND / ROOT CAUSE Performance in this functional area is consistent with the SALP level 3 rating.
4.
PERFORHANCE INFORMATION GAPS:
None D.
PLANT SUPPORf 1.
PERFORMANCE Performance in this functional areas was rated as 2 in the e
iast SALP (8/2/95),
The performance of the various organizations that are
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assessed in this functional are has been steady.
2.
PERFORMANCE BASIS The organizations assessed in this functional area continue
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to perform well, 3.
PERFORMANCE TREND / ROOT CAUSE The pe.*formance level in this functional area remains at the e
Category 2 level assessed by the SALP Soard.
4.
PERFORMANCE INFORMATION GAPS:
None s
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111. TIA STATUS Acceptability of single passive component for containment 9511A010 isolation requirements IV.
MAJOR SITE ACTIVITIES Planned:
E&TS - January 1996-V.
SMMMARY OF MIP CHANGES COOPER NUCLEAR STATION SEMIANNUAL PLANT PERFORMANCE REVIEW 95 04 OCTOBER 3, 1995 SUMMARY OF MIP CHANGES H000LE TITLE AREA IPE FM TO DELTA __
E-NONE
TOTAL
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PRE-DECISIONAL C00ptR WDCLEAR STATION
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BA5!$ FOR CONCERN Concerns have developed about Cooper Nuclear Station (CNS)l display individual because of a recent declining performance trend.
Although licensee personne pride in operating the plant well during reuttne operational periods, they fail
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to aggressively pursue and evaluate issues that are identified during periods of high activity such as non-routine operational or outage periods.
Performance during the recent refueling outage has shown significant weaknesses in the licensee's ability to identify and resolve potentially safety-significant problems. Licenses showed weakness in performing rigorous evaluations and proper resolutions to a number of technical. and safety issues.
In addition, the licensee appears satisfied with meeting specific regulatory requirements rather than fully considering the design basis and safety implications for maintaining equipment or ensuring system operability.
Senior plant management at corporate headquarters has maintained direct control over all site activities.
This fostered a middle management which has been reluctant to make decisions and always rely on upper management to make the final decision.
In addition, senior management established the number of non-conformance reports as one performance indicator which limited the number of corrective action documents, thus fostering an attituoe that senior management is neither dedicated to the aggressive pursuit nor the identification of problems.
A recent inspection identified that the licensee had provided inaccurate and incomplete information to the NRC in a response to a Notice of Violation. The licensee had incomplete documentation involving removal of start-up strainers and refused to believe the strainers were not removed. The licensee ir.:;tead relied on verbal statements from-the staff, on what they remembered, to verify the removal of the strainers.
The organization is resource limited and causes the management to be reactive
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rather than proactive. This reactive nature has been exacerbated by aging of the plant, a changed management team, and an increasing number of issues to be
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CURPENT STATUS The licensee has focused its inmediate attention to several issues recently identified by both by the licensee and the NRC To meet. the schedule, -the secondary containment test problems were
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resolved informally.
There was a rush to meet the schedule and get-a-valid secondary containment test so that defueling could be started.
Shutdown Cooling Pressure isolation Valves RHR-M0-17 and -18 exhibited
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leakage tuch '. hat a pressure increase occurred in the RHR system due to reactor coolant system leakage during plant operation.
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A safety-related service water valve for the RHR heat exchanger developed
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i a through-wall leak after only one cycle of operation.
In addition, erosion cf piping and other components by sandy Missouri River water in the Service Water System has been observed. Also, stagnant flow portions of the system have shown build-up of material, significantly restricting flow.
This safety-related heat removal system is not included in the Inservice Inspection program and has not received a hydrostatic pressure test since construction.
Diesel fuel oil particulate concentrations were above license procedural
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limit for several months before the licensee implemented corrective actions.
Deficiency reports for emergency condensate storage tank liner blisters,
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service water check valve erosion, and deficiencies in EQ MOV operators in ECCS systems, potentially significant issues have not been written.
The design reconstitution program is currently identifying deficiencies and concerns, the licensee is reviewing these concerns, and for the most part, addressing them adequately. Even though the progran is active in identifying and resolving concerns, they are one of the last plants to implement such a program.
In September 1992, construction stainers were identified as left in an emergency core cooling system.
The licensee received a violation for this finding, in February 1993, a special inspection was performed pertaining to construction strainers left in safety systems. This inspection revealed that the licensee's corrective actions to identify and resolve the issue of strainers in safety systems were inadequate.
These findings resulted in escalated enforcement and
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a civil penalty.
On March 6,1993, the licensee accidentally tripped a 4160v breaker, causing an isolation of the shut down cooling system just 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after a scheduled plant shut down. The cause of the event was personnel error, but the licensee's lack of effort during their initial rev12w has become a concern as to the effectiveness of their rev ew and resolution of events. This event occurred the
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day after the first week of inspection of the shutdown risk and outage management pilot inspection.
On March 8,1993, the licensee had difficulty with their secondary containment leak rate test which was required prior to moving fuel.
Upon routine investigation, the inspectors discovered that the licensee may not have adequately tested secondary containment, and that the situation may have existed for quite some time.
Followup of this item is still ongoing.
In March 1993, a corrective actions inspection was performed at the site to review the implementation of the corrective action program.
The inspection revealed several significant issues that were not being aggressively pursued by the licensee.
Tne major issues were SRV set point drift, primary boundary pressure isolation valve leakage, and diesel fuel oil particulate concentrations.
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The current assessment period ended on April 24, 1993.
The SALP board is scheduled to meet on May 20, 1993.
The previous SALP period was from July 16, 1990 through January 18, 1992, with
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the following ratings:
Plant Operations was rated a Category 2.
The licensee operated the plant well on a day to day basis, but when cht11enged by r.on-routine
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COOPER NUCLEAR STATION PRE-DECISIONAL
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svents or activities performed poorly.
Radiological *2ntrols was rated
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Category 2.
-This was a decline from previous asmu >nts.
Day-to-day performance was excellent, but poor. cosmiunications, coot @ wion, and controls -
were observed during the refueling outago. Maintenance /hrveillance was rated Category 1.
Increased management involvement and excellent maintenance and surveillance activities were noted. Emergency Preparedness was rated Category 2.
Weaknesses in the emergency exercise and in control room operator walk-throughs were noted.
Security was rated Category 1.
Management oversight and the performance of the security staff were a strength. Engineering / Technical Support-was rated Category 2.
Management's inability to adequately address concerns identified in previous assessment periods with the licensed opermt training program was noted. Safety Assessment / Quality Verification was rated Category 2.
Weaknesses were identified with the corrective action program in that the threshold for issuance of nonconNmance reports was too high to ensure that all
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potential deficient conditions wru identified.
Both erosion in high-flow regions, and corrosion product buildup in low-flow
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regions have recently been observed in the Cooper service water system.
Classification, inspection, and testing of this system are under review.-- A throttle valve in the service water system, RHR heat exchanger discharge valve MO-89A, was recently found to have a through-wall leak in the valve body.
The valve had only been in the system for one fuel cycle (18 months). This system, although needed to cool the diesel generators and remove long-term decay heat after an accident, is ANSI B31.1 Class 4 and is not in the ISI program. There is an ongoing regional corrective action inspection that will address the piping classification issue and the ISI program.
RHR pressure isolation valves (PIVs) MO-17 and M0-18 were recently observed.to be leaking during operation, when the RHR system pressure high alarms actuated.
Following shutdown, these valves were tested at containment accident pressure, 58 psi, to demonstrate compliance with Appendix J (Type C local leak rate tests).
One of the valves that leaked at RCS pressure successfully passed.the Type-C test. The other valve passed the Type C test in the reverse direction but failed in the accident direction. The licensee has_no requirement __to test any PIVs at greater than 58 psi and some valves are not leak rate tested at all.
The licensee is reviewing their PIV testing policy.
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The licensee has recently found that the secondary containment was not-isolated from the radwaste building.- The lack of isolation 'was not observed during-secondary containment leak testing because the testing.was conducted with the radwaste building HVAC system in operation which masked a 10-inch hole (pipe without a loop seal) running from insMe the reactor building to the radwaste building.
The licensee is conducting tests to determine whether or not-the secondary, containment can meet its Technical Specificatien requirements.
III.
FUTURE ACTIVITY
. Region.IV plans to conduct a public meeting in the vicinity of the facility in
.mid-May to discuss the licen.;ee's corrective actions during the outage to resche the plant hardware deficiencies.
A followup corrective action inspection is planned prior to plant startup from the refueling outage to verify satisfactory resolution of the hardwan issues that we identified during an earlier inspection.
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COOPER NUCLEAR STATION PRE-DECISIONAL
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NRC review of the' Inservice Inspection program is in progress.
System classification and inclusion of safety-related systems (i.e., the service water system) in the program is an issue.
The _ licensee's proposed changes to the battery Technical Specification is under NRC review.
The licensee has been requested to revise the proposed change to make it more contistent with the standard Technical Specifications.
The NRC review of the proposed upgrade of the EDG fuel oil Technical Specification is !n progress. Recent discovery of high particulate levels in the fuel oil at Cooptsr may have an impact on the review.
The licensee plans to submit an emergency Technical Specification change to modify the operability requirements for the core standby cooling system (CSCS)
area coolers. The basis for the change is an analysis showing that the coolers are not needed if v:ertain reactor building hatch plugs are removed, thereby enhancing natural circulation cooling of the RHR pump rooms in the reactor building.
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COOPER NUCLEAR STATION PRE-DECISIONAL DATA SUMMARY I.
OPERATIONAL PERFORMANCE A.
Scram Summary l
There have been no reactor trips during this period.
B.
Sianificant Doerator Errors An operator error on March 6, 1993, resulted in a loss of shutdown cooling (SDC) when he inadvertently opened the wrong breaker.
SDC was isolated for 24 minutes and flow reestablished 36 minutes after the system had initially been isolated. When SDC was reestablished, the reactor coolant had reached 190*F.
C.
Procedures On March 28, 1993, site personnel, during preparation for control rod unlatching, failed to follow procedures and removed seven reactor protection instrumentation system probes while the associated control rods were in the fully inserted position.
II.
CONTROL ROOM STAFFING A.
Number of Licensed coerators SM RQ Total Licensed Operators
8
8.
Number and Lenath of Shifts 5 shifts, 3 operating (8-hour shifts), 1-training, 1-off C.
Role of STA STAS are not assigned to a specific shift crew, nor d7 they receive training with a specific shift crew. STA's do not t.old a senior operator's license. The STA's primary duty is to act as an accident prevention and mitigation advisor to the shift supervisor.
D.
Recualification Proaram Evaluation A requalification program evaluation ~was conducted in November 1991.
The program was evaluated as satisfactory.
The next NRC requalification examination is scheduled for November 1993.
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e COOPER NUCLEAR STATION PRE-DECISIONAL III.
PLANT-SPECIFIC AND UNIQUE DESIGN INFORMATION A.
Plant-Specific Information Plant Cooper Nuclear Station Owner Nebraska Public Power District Reactor Supplier / Type GE/BWR-4 Capacity, MWe 778 MWe; 2381 MWt AE/ Constructor Burns & Roe Commercial Operation Date July 1, 1974 B.
Unioue Desian Information Emergency Core Cooling Systems:
Two loops of low-pressure core spray, two loops of low-pressure coolant injection, one high-pressure coolant injection system, one reactor core isolation cooling system, and an automatic depressurization system AC Power:
Five 345 Kv lines, one 161 Kv line and one 69 Kv line; two turbocharged, V-16, Cooper-Bessemer diesel generators DC Power:
Four Class lE batteries with 8-hour capacity (and four battery chargers), two 125-volt and two 250-volt.
IV.
SIGNIFICANT MPAs OR PLANT-UNIQUE ISSUES MPA B-105, Generic Letter 87-02, Seismic Qualification of Mechanical and Electrical Equipment in Operating Plants.
Licensee seismic analysis scheduled to be submitted 05/22/95.
I MPA B-lll, Generic Letter 88-20, Individual Plant Examination for Severe Accident Vulnerabilities.
Staff review of licensee response to GL 88-20 is in progress.
MPA B-li3, Generic Letter 89-19, Safety Implications of Control Systems, USI A-47.
Staff review of licensee response to GL 89-19 to be completed by 12/31/93.
MPA B-ll8, Generic Letter 88-20, Supplement 4,
Individual Plant Examination of External Events. Licensee IPEEE evaluation scheduled to be submitted 06/28/94.
MPA B-120, Generic Letter 92-01, Reactor Vessel Structural Integrity.
Staff review of licensee response to GL 92-01 to be completed by 12/31/93.
MPA B-121, Generic Letter 92-04, Reactor Water Level Instrumentation in BWRs.
Staff review of licensee response to GL 92-04 to be completed by 12/31/93.
MPA B-122, NRC Bulletin 90-01, Supplement 1, Loss of Fuel Oil in Rosemount Transmitters.
Staff review of licensee response to be completed by 12/31/94.
MPA L-208, Generic Letter 92-08, Thermo-Lag 330-1 Fire Barriers.
Staff l
review of licensee response to GL 92-08 is in progress.
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. COOPER NUCLEAR STATION PRE-DECISIONAL V.
-STATUS 0F THE PHYSICAL PLANT
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A.
Problems Attributed to Aoine
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The licensee's service water system has recently come to the NRC's-attention because of concerns with erosion and from potential pipe fouling from a build-up of deposits.
Two reactor coolant pressure isolation valves leaked and caused a pressure increase in a low pressure ECCS system.
These and other pressure isolation valves either receive an Appendix J 1eak rate test, or no leak rate tested at all.
B.
Other Hardware Issues The secondary containment failed its leak rate testing, partially due to inadequate maintenance of the airlocks and inadequate testing.
Feedwater check valves have experienced failures of Appendix J leak rate testing. The licensee implemented extensive modifications to these valves to-improve performance.
VI.
PRA A.
PRA Insichts Cooper is a BWR 4 with a Mark I containment. BWR PRAs indicate that station blackout is-a major contributor to core damage-frequency.
Offsite power for Cooper is supplied from a 161KV line and several 345KV lines that feed into.the startup transformer, and a 69KV line that feeds into an emergency transformer.
The 69KV power source supplies emergency loads only. The 69KV offsite power source has a poor record of spurious failures due to lightning strikes. After an SSFI revealed' voltage problems on the 69 KV line, a new substation was, added to help control the power. Since December 1992,.the 69KV power source has been reliable.
The Emergency Diesel Generators (EDGs) require control air to maintain a s=6 engine speed-and provide protective trip functions.
If control air is lost, the EDGs will shut down.
Cracking of instrument air tubes has occurred due to vibration resulting in diesel engine trips.
Relocation of engine mounted instruments has apparently rectified the situation in that for approximately the past 1 1/2 years there have been no diesel engine trips because of that situation.
Published PRAs provide a strong indication that service water systems are risk significant. At Cooper, the SWS is not treated as an ASME Code Class 3 system.
Although the SWS is included in the IST program, it is not included in the ISI program. Therefore, SPSB believes that the treatment of the SWS failure rates should be evaluated carefully by RES during the IPE review process.
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COOPER NUCLEAR STATION PRE-DECISIONAL B.
PRA Profile In response to Generic Letter 88-20, the licensee recently submitted an IPE for Cooper on March 31, 1993.
In the IPE submittal, which contains a Level 1 PRA and a Level 2 PRA, the estimated mean core damage frequency is 7.97E-5 per year.
The IPE submittal does not provide a summary of the risk profile in terms of initiating events and sequence contributions u core damage frequency.
It does provide a risk profile in terms of accident type, which is presented below.
Accident Type
% of Core Damage Frequency Station Blackout 34.8%
Loss of Coolant Injection 18.1%
Loss of Containment Heat Removal 10.9%
ATWS 4.9%
LOCAs 0.9%
Fast Containment Failures 0.1%
')n the basis of a coarse review of the IPE by SPSB, it appears that che loss of Containment Heat Removal category refers to sequences initiated by Loss of Service Water. The Loss of Coolant Injection category appears to include sequences involving any type of transient with no injection systems of the required pressure available.
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C.
fore Damace Precursor Events On the basis of the precursors identified by ORNL for 1991 (NUREG/
CR-4674, vols. 15 and 16) and the preliminary precursors for 1992, SPSB did not identify any precursor events for the unit that have a conditional core damage probability of IE-5 per year or greater.
VII. ENFORCEMENT HISTORY SIGNIFICANT ENFORCEMENT HISTORY (Since April 1991)
MARCH 1992 ENFORC. MENT CONFERENCE -
Two Severity Level IV (EA 92-043)
violations involving the failure to take corrective actions for degraded station 250-volt batteries and failure to follow procedures involving operability evaluations.
REACTOR OPERATIONS -
SUPPLEMENT I, AND MISCELLANEOUS MATTERS -
SUPPLEMENT VII MARCH 1993 CIVIL PENALTIES - The action was based on two Severity (EA 93-30)
Level III violations associated with: (1) providing inaccurate information to the NRC in response to a Notice of Violation, and (2) the failure to identify and correct a potentially significant condition idverse to quality, after the 1992 discovery of a strainer that had i
been left in a safety system since initial startup.
Civil penalties were issued to emphasize the licensee's
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COOPER NUCLEAR STATION PRE-DECISIONAL
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need to. improve its problem identification and
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resolution programs.
Although mitigation was appropriate for the licensee's previou: good performance regarding the accuracy of submitted infori;;3 tion, it was offset by the escalation for NRC identificatM and the licensee's failure to act upon information w;.hh indicated that its submission was inaccurate.
Mitigation of the civil penalty was appropriate for licensee identification, but was offset by the escalation for failure to act upon prior opportunities to identify the presence of strainers and poor licensee performance in the area of corrective actions.
($200,000)
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COOPER MOST RECENT SALP RATINGS l
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OPS RAD M/S EP SEC ET SAQV SALP PERIOD E 4/16/89-7/15/90
'e 7/16/90-1/18/92 L_J 1/19/92-4/24/93
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COOPER STATION
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Cause Codes (ALL LERs)
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'f PRE-DECISIONAL,
^
COOPER I.
HISTORY Cooper Nuclear Station was first discussed at the June 1993 Senior Management Meeting (SMM).
The basis for concern was an apparent declining performance.
Although licensee personnel displayed individual pride in the plant and seemed to operate the plant well during routine-operational periods, they failed to aggressively pursue and evaluate issues that were identified during periods of high activity, such as-non-routine operational / outage periods.
Performance
,
during the refueling outage showed significant weaknesses in the-ability to'
-identify and resolve technical / safety issues.
Senior management at corporate headquarters had maintained direct control over all site activities.
This may have fostered a middle management that was
-
reluctant to make decisions and always relied on upper management to make the final decision, in addition, senior management established performance indicators that apparently limited the number of corrective action documents, thus-fostering an attitude in the organization that senior management was not dedicated to either identifying-or aggressively pursuing problems.
-In 1992, the licensee had provided inaccurate and incomplete information to the-NRC in-a response to a Notice of Violation.
The licensee had incomplete
-
documentation for an issue involving removal of start-up strainers and refused to believe-that the removal was also incomplete.
Instead, the licensee relied on oral reports that the strainers had been-removed when, in fact, some were still in place.
Management appeared to be reactive rather than proactive. The organization was
'
resource limited.
Aging of the plant, a changed management team, and an increasing r. umber of issues apparently taxed the organization's ability to adequately resolve-the concerns and issues identified.
l II.
CHANGES SINCE LAST SMM Since the last SMM, licensee performance continued to decline, based on issues identified in the areas of maintenance, engineering, and safety-assessment /
quality verification.
Pei formance, has improved in the area of radiation protection, and has remained mix (d in operations and emergency preparedness. The dominant concern has been a lack of a questioning attitude with-a tendency to work around problems,- and a high threshold for identifying - problems to the Corrective Action Program. This attitude was observed in nearly all functional areas and was found at essentially all-levels of involvement.
An NRC corrective actions -inspection performed in April and May 1993 identified several issues which required resolution prior to the plant returning to power operation. These issues were discussed at a public management meeting on June 22 at the site:and included 1) inoperability of the secondary containment because of inadequate testing, 2) pressure isolation _ valves that were leaking and
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pressurizing low. pressure systems, 3} particulate material in the diesel fuel and k) analyzer, 5) service water oil, 4) potential inoperability of th drywell H local leak rate testing piping: not tested under the ISI p.ogram, deficiencies. -The licensee also presented the results of its reviews that identified other conditions to be resolved. A Corrective Action Program Overview Group (CAP 0G) was established to perform this review and has continued to
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COOPER PRE-DECISIONAL l
(
function to overview site corrective actions pending the implementation of a revised corrective action program and improved self-assessment capability.
Escalated enforcement action was subsequently taken as a result of these issues.
,
The NRC subsequently reviewed the pressJre ~ isolation ValPP leakage issue for
'
interfacing system LOCA considerations and determined that there may have been a significant level of risk depending on the physical conditions of the plant, but the licensee had indicated a lack of appreciation for the risk of interfacing system LOCA.
The licensee subsequently formulated a Corrective Action Program Self-Assessment Group to eval. ate management effectiveness and corrective action program content, method, implementation and effectiveness. The corrective action program had been viewed by workers as a regulatory program, and management's expectations for the corrective action program had not been well communicated or understood by working level personnel. The licensee's corrective action program had not been effective in identifying personnel performance errors, and trend reports were not effectively used by management for monitoring the corrective action program status. The licensee has initiated actions to overhaul their corrective action process, and the region is closely monitoring their progress.
The licensee announced a reorganization in September that involved the relocation of a number of senior managers from their headquarters offices to the Cooper site.
The licensee also named an INP0 2-year loanee as their new Manager, Systems Engineering.
A shutdown risk pilot inspection identified, during the refueling outage, that the licensee had removed the reactor vessel head and the vessel internals in i
March 1993 prior to establishing secondary containment integrity.
It was subsequently determined that these actions were not in compliance with the licensee's Technical Specifications (TS). This issue is under 01 investigation to determine if it represents a willful violation of TS.
On July 12, a public meeting was conducted with the licensee to discuss the results of the most recent SALP for the period of January 19, 1992, through April 24, 1993.
Because of the numerous equipment problems and the failure of the licensee to self-identify and correct the problems, the areas of Maintenance / Surveillance and Safety Assessment / Quality Verification were assigned ratings of Category 3.
Engineering / Technical Support was rated as Category 2.
Significant weaknesses were identified in problem resolution by the site engineering group. Operations was rated as Category 2.
A lack of a questioning attitude on the part of the operating staff for some engineering operability determinations was observed.
There were recurring problems in Emergency Preparedness, and this area was assigned a Category 2 with a declining trend.
Radiological Controls was assigned a Category 2 rating with an improving trend, and Security was assigned a Category I rating.
The licensee continued to demonstrate weaknesses such as a lack of questioning attitude, ineffective problem resolution, and a lack of agressiveness in dealing with plant problems. The following issues were identified subsequent to the SALP meeting:
The licensee began a reactor startup from the 138-day refueling /mainte-
.
i nance outage on July 21.
The outage had been scheduled for 56-days; however, emergent work activities, particularly in the area of motor
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COOPER PRE-DECISIONAL.
operated valve testing, and the repairs to service water piping and components that had experienced excessive erosion / corrosion, resulted in the extended outage.
Other ma'jor work activities completed included inspection of the torus and installation of the wetwell hardened vent.
On July 23, the licensee shut down the reactor and declared a Notification
of Unusual Event because of the Missouri River flood affecting emergency evacuation routes. Significant building water inleakage was noted because of the increased water table from the flooding and because of the licensee's failure to pump out storm drains around the plant that had been flooded from recent thunderstorms.
Significant NRC involvement was required before the licensee formulated a plan to identify, mitigate, and recover from the effects of the water inleakage.
On August 30, a motor-operated valve failed to stroke because the licensee
had failed to secure (stake) the motor pinion key as suggested by the vendor in 1989 and the key fell at of the shaft, rendering the motor operator inoperable.
The licensee found other safety-related valve operators that had been modified prior to 1991 and had keys and set screws
that were not properly secured.
Following the repairs to the motor operated valve that failed on August 30, the valve again failed to stroke during post-maintenance testing.- Foi eign material (trash, paint chips, and metal filings) was found in the relay starter box for the valve.
A piece of this material had prevented the relay contacts from closing, inspection of starter boxes for other motor-operated valves foend seven additional boxes with foreign material that could have impacted the operability of the valves.
~
On November 8, a safety concern was identified with the emergency diesel
generators output breakers.
A scenario in which an emergency diesel generator automatically started, came up to_ rated speed and voltage, and was followed by a loss of offsite power would result in the EDG output breaker's failure to automatically close.
The licensee declared both diesels inoperable and declared an unusual event, which forced a reduction in power.
The declaration of the unusual event was not made until prompted by the plant manager.
The possibility exists that the relays for the generator output breaker
permissive circuit may not have been functioning properly since plant startup in July 1993.
Preliminary findings of a special inspection identified that the procedures for tesung the relays were inadequate, some data (as-found condition of the relays) was not recorded, vendor instructions concerning the relays were not followed, and inadequate
-
corrective action was taken based on the original root cause determination.
An Operational Safety Team inspection (OSTI) conducted in November concluded that there was a general lack of management direction and control of ruutine and complex operations, and there had been a breakdown in vertical communications in operations, maintenance, and engineering activities.
Examples were found of procedure inadequacy and failure to follow procedures in the areas of operations and maintenance.
The OSTI also found that the training of shift technical advisors (STAS), the fire brigade, and the operators of the remote shutdown panel
'
was unacceptable.
System engineers had not been trained on their assigned
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COOPER
,
PRE-DECISIONAL systems, and inspectors had not been trained on the acceptance criteria to be used for fire barrier doors. Maintenance work practites were poor. Work orders were only marginally adequate, post-maintenance f esting wn not always defined, preventive maintenance required by the vendor was tot behg performed, and about half of the maintenance act-ivities were defined at -troubleshooting, which implemented corrective maintenance without the need int work instructions.
Engineering backlog was high, and engineering configuration management was weak, which resulted in uncontrolled installatfon of insulation on safety-related equipment.
Pipe supports were taken apart and not restored, design changes were implemented by maintenance work requests (not modification requests), and drawings were not updated promptly after design change implementation.
Management had not established a means of assessing human performance, and they were ineffective in resolving problems such as weaknesses in STA training, fire brigade training, and fire door inspection practices.
Management had also arbitrarily extended the due dates of QA-identified problems. The OST) findings are currently under review in Region IV.
III.
FUTURE ACTIVITY An Operational Safeguards Response Evaluation (OSRE) scheduled for March 1994 A Service Water Team Inspection scheduled for March 1994 The licensee plans to extend the current cycle to have the next refueling outage in February 1995.
The licensee plans to implement its revised Corrective Action Program in early 1994 i
I
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__
.
COOPER PRE-DECISIONAL DATA SUMMARY I.-
OPERATIONAL PERFORMANCE A.
Scram Summary None B.
Sionificant Doerator Errors None C.
Procedures During the past few months, several examples of plant events and problems have been caused by the failure to follow procedures and inadequate procedures.
For example, the OSTI found several examples where procedures :were not usable as written and that workers were performing steps outside of the procedure.
Also, the calibration procedures for emergency diesel generator relays were inadequate, and as a -result, an electrician mis-set relays in both diesels, which rendered them inoperable.
II.
CONTROL ROOM STAFFING A.
Number of Licensed Goerators 18.Q E.Q.
101 %
Licensed Operators
14
B.
Number and Lenath of Shifts Six 12-hour shifts C.
Role of STA The STA's at Cooper Nuclear Station are on duty for ' a 24-hour rotational period.
They are not assigned to a specific shift crew; however, they do receive training with a specific shift crew.
STA's do not hold a senior reactor operator's license.
The STA's primary duty is to act as an accident prevention and mitigation advisor to the
,
shift supervisor.
D.
Recualification Procram Evaluation In November 1991, the NRC administered requalification examinations at Cooper, The requalification training program was determined to be effective and was assigned an overall program rating of satisfactory,
_
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COOPER
.
PRE-DECISIONAL The NRC completed a requalification program evaluation in December 1993 and four,d that command and control had improved over that found in the previous evaluation.
III.
PLANT-SPECIFIC AND UNIQUE DESIGN INFORMATION A.
Plant-Specific Information Plant Owner Cooper Nuclear Station Nebraska Public Power District Reactor Supplier / Type GE/BWR Capacity, MWe
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778 AE/ Constructor Burns & Roe Commercial Operation-Date July 1, 1974 B.
Unioue Desion Information Containment: Mark I, with a hard vent Emergency Core Cooling Systems: Two loops of low-pressure core spray, two loops of low-pressure coolant injection, one high-pressure coolant injection system, one reactor core isolation cooling system, and an automatic depressurization system AC Power:
turbocharged, V-16, Cooper-Bessemer diesel generatorsFive 345 K DC Power:
battery chargers), two 125-volt and two 250-volt.Four Class IE batterie IV.
SIGNIFICANT MPAs OR PLANT-UNIQUE ISSUES MPA B-105, Generic Letter 87-02, Seismic Qualification of Mechanical and Electrical Equipment in Operating Plants.
Licensee seismic analysis scheduled to be submitted 05/22/95.
MPA B-lll, Generic letter 88-20, Individual Plant Examination for Severe Accident Vulnerabilities.
GL 88-20 is in progress.
Staff review of licensee response to MPA B-ll3, Gencric Letter 89-19, Safety implications of Control Systems, USI A-47.
Staff review of licensee response to GL 89-19 to be completed by 12/31/93.
MPA B-118, Generic Letter 88-20, Supplement 4,
Individual Plant Examination of External Events.
Licensee IPEEE evaluation scheduled to be submitted 06/28/94.
MPA B-120, Generic Letter 92-01, Reactor Vessel Structural Integrity.
Staff review of licensee response to GL 92-01 to be completed by 12/31/93.
}
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COOPER PRE-DEclS10NAL, MPA B-121, Generic letter 92-04, Reactor Water Level Instrumentation in BWRs.-
Staff review of licensee response to GL 92-04 to be completed by 12/31/93.
MPA B-122, NRC Bulletin 90-01, Supplement 1, Loss of Fuel Oil in Rosemount Transmitters.
Staff review of licensee response to be completed by-12/31/94.
MPA L-208, Generic Letter 92-08 Thermo-Lag 330-1 Fire Barriers.
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Staff review of licensee response to GL 92-08 is in progress.
,
V.
STATUS OF THE PHYSICAL PLANT A.
Problems Attributed to Aoine During the period when the Missouri River level was high in July, a considerable amount of ground water intruded into the reactor and turbine buildings. This was likely to be caused by age degradation of building seals.
B.
Other Hardware Issues The radiation monitors (manufactured by'lding and for monitoring the Kaman) used for monitoring the radiation levels in - the reactor bui gaseous releases from the elevated release point, the turbine-building, and the-radwaste building have experienced repeated failures.
VI.
PRA A.
PRA Insichts Cooper _is a-BWR-4 with a Mark I containment.
BWR PRAs indicate that station blackout is a major contributor to_ core damage-frequency.
Offsite power for Cooper -is supplied from a 161kV line and several 345kV lines that feed _into the start-up transformer, and a 69kV line that feeds -into an emergency transformer.
The 69kV - power source =
supplies emergency loads only and has had a poor-record of spurious-
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failures due to lightning strikes.
After an SSFI revealed voltage problems on the 69 kV line, a new substation was added-to help control
- the power.
Since December 1992,- the '69kV power source has been reliable,
,
The Emergency Diesel Generators (EDGs) require control air to maintain a set engine speed and provide protective trip functions. If control air-is lost, the EDGs will : shut-down.
Cracking of instrument air tubes has occurred due to vibration resulting in diesel engine trips.
Relocation of engine mounted instruments has apparently rectified the situation in-that, for approximately the past two years, there have been no dies,el engine trips because of that situation.
Published PRAs provide a strong indication that service water systems are risk significant.
In the past year, Cooper has experienced microbiological 1y induced corrosion in certain sections of piping
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COOPER PRE-DECISIONAL associated with the SWS stagnant or low flow co(radiation monitor sample line) as a result of nditions.
identify sections of piping subject to these same conditions.The entire SWS identified sections of piping were inspected and no similar conditions All were found.
At Cooper, the SWS was not originally designed as an ASME Code Class 3 system.
Although the SWS is included in the IST program, it has not been included in the ISI program in accordance with the provisions of 10 CFR 50.55a(S).
Therefore the treatment of the SWS failure r, SPSB has suggested to RES that carefully during the IPE review process.ates should be evaluated The licensee plans to include the SWS in the 151 program starting with the next refueling outage in 1995.
B.
PRA Profile in response to Generic letter 88-20, the licensee submitted an IPE for
. Cooper on March 31, 1993.
In the IPE submittal, which contains a Level 1 PRA and a Level 2 PRA, frequency is 7.97E-5 per year.
the estimated mean core damage the contractor TER should be complete in January 1994.The RES IPE r submittal does not provide a summary of the risk profile in terms of The IPE it does provide a risk profile in terms of accident typeinit presented below.
, which is
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Accident Tvoe
% of Core Damaae Freauency Station Blackout Transient Induced LOCAs 34.8%
Loss of Coolant Injectior 30.3%
Loss of Containment Hea 18.1%
N, ATWS 10.9%
LOCAs 4.9%
Fast Containment failur a 0.9%
0.1%
Because the IPE was sumn, in terms of accident type, a coarse
,
review of the IPE by SPSB we performed to try to categorize the risk profile it terms of initiators and seque damage frequency for comparison purposes.nce contributors to core On the ba is of this refers to sequences initiated by loss of Service Water. review Coolant Injection category appears to include sequences involving any The Loss of type of transient with no injection systems of the required pressure available.
C.
Core Damaae Precersor Events On the basis of the precursors identified by ORNL for 1991 (NUREG/CR-4674, vols. 15 and 16) and the preliminary precursors for 1992, SPSB did not identify any precursor events for the unit that have a conditional core damage probability of IE-S per year or greater.
The following event has been preliminarily screened as a "Significant Event" by the Events Assessment Panel.
'
From May 1992 until March
_ _ _ - _ - _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ -
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i,
COOPER PRE-DECISIONAL-1993, Cooper continued to operate with RCS leakage, at a rate of approximately 0.4 gpm, through both isolation valves of the shutdown cooling suction line.
This rate was sufficient to require the operators in establish a relief path from the suction line to the ECCS keep-filled.s/ stem.
During the March 1993 refueling outage, the licensee disassembled and inspected both valves (for the first time)
and found cracks in the seats and discs. SPSB reviewed this event for its implications with respect-to interfacing system LOCA.
It is not possible to calculate a conditional core damage probability for this event since there is no means available to determine the probability of failure for the suction isolation valves during the period of interest at Cooper, given the degree of leakage observed and cracks found.
If Cooper had experienced gross failure of the RHR suction line isolation valves, the event would have been highly risk significant.
Therefore, the physical condition of the plant may or may not have created a significant level of risk.
However, the actions of the licensee indicated a lack of appreciation for the risk associated with an Interfacing Systems LOCA.
.
VII.
ENFORCEMENT HISTORY 3/92 ENFORCEMENT CONFERENCE - Two Severity Level IV violations involving the failure to take corrective actions for degraded station 250-volt batteries and failure to follow procedures involving operability evaluations, 3/93 CIVIL PENALTIES-The action was based on two Severity Level III violations associated with (1) providing inaccurate information to the NRC in response to a Hotice of Violation, and (2) the failure to identify and correct a potentially significant condition adverse to quality, after the 1992 discovery of a strainer that had been left in a safety-system since initial start-up.
Civil penalties were issued to emphasize the licensee's need to improve its problem identification and resolution programs.
Although mitigation was appropriate for the licensee's previous good performance regarding the accuracy of submitted information, it was offset by the escalation for NRC identification and the licensee's failure to act upon information which indicated that its submission was inacc ate.
Mitigation of the civil penalty was appropriate for licensee identification, but was offset by the escalation for failure to act upon prior opportunities to identify the presence of strainers and poor licensee performance in the area of corrective actions.
(5200,000)
10/93 CIVIL PENALTIES - The action was based on three Severity Level III violations associated with (1) several violations of 10 CFR 50 which collectively indicate a breakdown in the licensee's corrective action program; (2) the failure to maintain the containment hydrogen / oxygen analyzers in an operable condition; and (3) the failure to include the service water and reactor equipment cooling systems in the inservice inspection program since initial plant operations. Civil penalties were issued to emphasize the significance that the NRC attaches to these
,
__-
COOPER
.-
PRE;DECISIONAt.
violations and the importance that the NRC attaches to NPPD's efforts to resolve deeply rooted and fundamental weaknesses in-
_
employee attitudes' toward-identifying and resolving problems.
The civil penalty associated with the corrective action-program was escalated for-NRC identification. ($75,000)_ The civil'
penalty associated with the inoperable hydrogen / oxygen analyzers -
was escalated for NRC identification and opportunities to identify the multiple licensee licensee's corrective actions (problem but mitigated for the
$75,000).
The civil penalty associated with the failure to include the service water and
-
reactor equipment cooling' system > in.the inservice-inspection program was not adjusted ($50,000).
(Total: $200,000)
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COOPER STATION ' ' S"* 5 ' ' ' ' "' ' 5' " * "' ' " " " " Peer Group General E6ectric Pre-Tu uese m 90-4 to 93-3 TreNs ord Denotions
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PRE-DECISIONAL - . COOPER I.
HISTORY Cooper Nuclear Station was first discussed at the June 1993 Senior Management Meeting (SMM).
The basis for concern was arr: rent declining performance.
Although licensee personnel displayed individual pride in the plant and seemed to operate the plant well during routine operational periods, they failed to aggressively pursue and evaluate issues that were identified during periods of high activity, such as non-routine operational and outage periods. Performance during the 1993 refueling outage showed significant weaknesses in the ability to identify and resolve technical and safety issues.
Senior licensee management had a leadership style that resulted in middle management being reluctant to make decisions. The management team was reactive and not proactive.
The licensee's organization has been resource limited, and with the increasing number of issues being identified, the organization's ability to adequately resolve the concerns and issues has been weak.
As discussed at the SMM in January 1994, senior management has moved to the site to provide management direction for site activities.
Management and key personnel have become increasingly stressed as the work load and number of plant issues identified continued to increase.
Due to continuing decline in overall performance Cooper was issued a trending letter in January 1994.
The senior managers were developing an aggressive Near Term Integrated Enhancement Program to ensure that continued improvements in plant performance are realized.
II.
CHANGES SINCE LAST SMM Since issuance of the trending letter, the decline in the licensee's performance has stopped and appears to have stabilized.
Additional issues have been identified, but for the most part, the licensee's identification and approach to correct these problems has shown improvement.
The dominant concern has been a lack of management's ability to get a commitment from plant employees at all levels to improve their performance. The most recent performance data indicates that improvements at the site appear to have reached the first line of ' supervision; however, many of the workers still do not have a clear understanding of management's expectations. This lack of understanding appears to limited to only a few functional areas.
Significant inspection findings since the last SMM include: The licensee's failure to rigorously investigate and determine the root
cause of a reactor scram on March 3 that resulted in the actuation of the high pressure coolant injection system.
Licensee personnel did not discover the cause of the event until they were in the process of starting up the reactor and received uncontrolled fluctuations of the turbine by-pass valves.
, The licensee had to shutdown the plant to repair a leaking RHR isolation
valve that had been caused by foreign material (weld slag) on the seating surface.
Also during this shutdown, a coi.tainment isolation vent valve
- P
. COOPER PRE-DECISIONAL . ' had to be repaired due to foreign material.
In both cases foreign material was introduced during the previous outage.
On April 11, 1994, the licensee was unable to meet the design requirements
for the control room pressure envelope and over 50 leaks were identified by the licensee. The control room envelop, in all likelihood, has never been capable of performing its design function under all design conditions.
These activities indicated that the licensee is beginning to become more diligent in their efforts to identify and correct problems and/or concerns, but the depth of their efforts and their thoroughness in resolving the issues continues to be a concern.
Mid-level managers and first-line supervisors addressing these concerns have generally not received prior training on the tasks they are assigned to perform.
To address the issues discussed above and the other issues previously identified during past inspection activities, the licensee completed the formulation of a ' Near-Term Integrated Enhancement Program (IEP), which identifies the causes for the declining performance at Cooper and outlines the proposed actions that the licensee plans to implement to resolve these issues. The licensee identified the three most significant challenges as: (1) changing the culture in the maintenance department, (2) obtaining employee ownership of the required improvements, and (3) developing rigor and consistency in the handling of reactive issues.
The licensee's IEP has been effective in identifying personnel performance errors, and the licensee's periodic trend reports have been effectively used by management for monitoring the IEP status.
) Management changes continue to be discussed by licensee management, but the implementation of these changes are not evident.
Only staff additions to engineering, chemistry, and health physics have been implemented.
The most recer.t SALP was performed in July 1993.
Because of the numerous equipment prcolems and the failure of the licensee to self-identify and correct the problems, the areas of Maintenance / Surveillance and Safety Assessment / Quality Verification were assigned ratings of Category 3.
Engineering / Technical Support was rated as Category 2 with significant weaknesses in problem resolution by the site engineering group. Operations was rated as Category 2 based on a lack of a questioning attitude on the part of the operating staff for some engineering operability determinations.
Recurring problems in Emergency Preparedness were noted and this area was assigned a Category 2 with a declining trend.
Radiological Controls was assigned a Category 2 rating with an improving trend, and Security was assigned a Category I rating.
An evaluation of the licensee's nerformance indicates that the area of Maintenance / Surveillance has not impraved. Problems continue to occur throughout this area.
The licensee's approach to correcting identified problems has improved so as to mitigate or reduce potential reoccurrences.
Maintenance backlog has remained steady and appears manageable at this time.
Plant engiraering has exhibited improvement.
The new Engineering Manager is taking a very active role in almost every issue that has surfaced in recent months. There appears to be a willingness by the engineers to perform well and !
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ COOPER PRE-DECISIONAL tha Engineering Manager in pr'sently assembling a set of standards and guidelines so as to assess the engineers' depth of knowledge and capabilities.
Housekeeping is improving in most areas of the plant.
With the reduction in radiologically contaminated areas, plant personnel are able to better maintain equipment and areas. There continue to be areas of concern with respect to the material condition of plant equipment (diesel generators, feedpumps, CRD pumps, hydrogen seal oil).
There has been a visible improvement in the presence of quality assurance (QA) and self-assessment personnel throughout the plant.
The Division Manager and several other managers have been moved to the siia, and QA has taken an active role in day-to-day plant activities.
The findings identified by QA audits are receiving better plant management attention for resolution, but improvement in addressing the findings is needed.
Plant Operations performance is mixed.
There is indication that the shif t operators have taken responsibility and are exercising firmer control of shift activities and decisions. A recent inspection identified weaknesses in several operational crews pertaining to their understanding of emergency are)aredness reor 'ements, with significant weaknesses identified in one part' cu' ar crew.
Con ' room operator response to the recent reactor scrams and the loss of shut n cooling appeared to be effective, but a noticeable lack of mid-level manas sent invohement continues to exist.
!!!. FUTURE ACTIVITY , An Engineering and Technical Support Inspection is scheduled for June 1994.
An end-of-sal.P-cycle inspection will be performed in August 1994.
An Operational Safeguards Response Evaluction (OSRE) is scheduled for 1995.
The licensee is planning to extend the current cycle to have the next refueling outage in February 1995.
The licensee plans to implement its Nuclear Business Plan in mid 1994.
This document will then take t'1 place of the Near Term IEP.
_________---j
-. _. _. _. _ _ _ _ _ _ _ _ _ _ _. . _ _ - . COOPER PRE-DECISIONAL DATA $UMMARY 1.
OPERATIONAL PERFORMANC.E A.
Isram. Sunnar_v There has been I reactor scram from power dur: 19 this period.
On March 2,1994, a partial closure of the turbine governor valves caused a pressure increase and the reactor scrammed on high flux.
B.
Jinnificant Operator Errors None C.
Procedures During the past few months, several 11 ant events and problems have been caused by the failure to follow procedures and inadequate procedures, tor example, the calibration procedures for emergency diesel generator relays were inadequate, and as a result, an electrician incorrectly set relays associated with both diesels, which rendered them inoperable.
II.
CONTROL ROOM $TAFFING A.
Number of Licensed Operators g SEQ RQ 1016.L Licensed Operators
14
B.
Number and Lenath of Shifts 6 shifts, 12-hour shifts C.
Role of STA The STAS at Cooper Nuclear Station are on duty for a 24-hour rotational period.
lney are not assigned to a specific shift crew; however, they do receive training with a specific shift crew. STAS do not hold a senior reactor operator's license. The STA's primary duty is to act as an accident prevention and ritigation advisor to the shift supervisor.
D.
Reaualification Procram Evaluation A requalification program evaluation conducted in December 1993 resulted in a satisfactory rating for the program. Reg' ion IV will conduct an inspection in accordance with IP-71001, " Licensed Operator Requalification Program Evaluation," during the month of November 1995.
I
l - COOPER PRE-DECISIONAL !!!. PLANT-SPECIFIC AND UNIQUE DESIGN INFORMATION A.
Plant-$necific Information Plant Cooper Nuclear Station Owner Nebraska Public Power District Reactor Supplier / Type GE/BWR Capacity, MWe 778 AE/ Constructor Burns & Roe Commercial Operation Date July 1, 1974 B.
Uniaue Desian Information Containment: Mark I, wi1h a hard vent Emergency Core Cooling S Two loops of low-pressure core spray, two loops of low-pressur) stems:e coolant injection, one high-pressure coolant injection system, one reactor core isolation cooling system, and an automatic depressurization system.
AC Power: Five 345 Kv lines, one 161 Kv line and one 69 Kv line; two turbocharged, V-16, Cooper-Bessemer diesel generators.
DC Power: Four Class lE batteries with 8-hour capacity (and four battery chargers), two 125-volt and two 250-volt.
IV.
$1GNIFICANT NPAs OR PLANT-UNIQUE !$$UES MPA B-105, Generic Letter 87-02, Seismic Qualification of Mechanical and Electrical Equipment _ in Operating Plants.
Licensee seismic analysis scheduled to be submitted 05/22/95.
MPA B-111 Generic letter 88-20, Ir.dividual Plant Examination for Severe Accident Vulnerabilities. Staff review of licensee response to GL 88-20 is in progress.
MPA B-ll8, Generic letter 88-20, Supplement 4 Individual Plant Examination of External Events.
Licensee IPEEE evaluation scheduled to be submitted 06/28/94.
V.
STATUS OF THE PHYSICAL PLANT , GROUND WATER PROBLEM: During the period when the Missouri River level was high in July, a considerable amount of ground water intruded into the-reactor and turbine buildings.
This was likely to be caused by < degradation of building seals.
RADIATION MONITORS: The radiation monitors (manufactured by Kaman) used for monitoring the radiation levels in the reactor building and for monitoring the gaseous releases' from the elevated release point, the turbine butiding, and the radwaste building have experienced repeated failures.
. ' S ,
_ - - _ _ _ _ - _____ - __-__ COOPER PRE-DECISIONAL VI.
PRA A.
PRA insichts Cooper is a BWR 4 with a Mark I containment.
BWR PRAs indicate that station blackout is a major contributor to core damage frequency.
Offsite power for Cooper is supplied from a 161KV line and several 345KV lines that feed into the start-up transformer, and a 69KV line that feeds into an emergency transformer.
The 69KV power source supplies emergency loads only.
The 69KV offsite power source has a poor record of spurious failures due to lightning strikes.
After an SSfl revealed voltage problems on the 69 KV line, a new substation was added to help control the power. Since December 1992, the 69KV power source has been reliable.
Th^ Emergency Diesel Generators (EDGs) require control air to maintain a set engine speed and provide protective trip functions. If control air is lost, the EDGs will shut down.
Cracking of instrument air tubes has occurred due to vibration resulting in diesel engine trips.
Relocation of engine mounted instruments has apparently rectified the situation in that for approximately the past two years there have been no diesel engine trips because of that situation, in the event of a station blackout, the 250V and 125V DC batteries have the capacity to I accommodate the loads for a duration of 8 hours without load shedding.
Published PRAs provide a strong indication that service water systems are risk significant, in the past year, Cooper has experienced l microbiological 1y induced corrosion in certain sections of piping associated with tne SWS (radiation monitor sample line) as a result of stagnant or low flow conditions.
The entire SWS was reviewed to identify sections of piping subject to these same conditions.
All identified sections of piping were inspected and no similar conditions were found. At Cooper, the SWS was not originally designed as an ASME Code Class 3 system. Although the SWS is included in the IST program, it has not been included in the ISI program in accordance with the provisions of 10 CFR 50.55a(g). Therefore, SPSB has suggested to RES that the treatment of the SWS failure rates should be evaluated carefully during the IPE review process.
The licensee plans to include the SWS in the 151 program starting with the next refueling outage in 1995.
B.
FRA Profile In response to Generic Letter 88-20, the ifcensee submitted an IPE for Cooper on March 31, 1993. The IPE was performed by a team made up of licensee staff and SAIC personnel.
In the IPE submittal, which contains a Level 1 PRA and a Level 2 PRA, the estimated mean core damage frequency is 7.97E-5 per year. The RES review of the IPE is in progress but as of April,1994 a completion date has not been set.
The IPE submittal does not provide a summary of the risk profile in l terms of initiating events and sequence contributions to core damage j frequency, it does provide a risk profile in terms of accident type, which is presented below.
I
!
. _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _
-. COOPER PRE-DECISIONAL . Accident Tyne % of CDF Station Blackout 34.8% Transient induced LOCAs 30.3% Loss of Coolant injection 18.1% Loss of Containment Heat Removal 10.9% ATWS 4.9% LOCAs 0.9% Fast Containment Failures 0.1% Because the IPE was summarized in terms of accident type, a coarse review of the IPE by SPSB was performed to try to categorize the risk profile it terms of initiators and sequen damage frequency for comparison purposes. ce contributors to core On the basis of this review, it appears that the Loss of Containment Heat-Removal category refors to sequences initiated by Loss of Service Water.
The loss of Coolant Injection category appears to include sequences involving any type of transient with no injection systems of the required pressure available.
The most do:ninant contributors to accident sequences that lead to core damage were found to be failure of the EDGs to continue to run, mechanical failures of the HPCI and RCIC systems and RCIC-turbine, common cause failure (CCF) of all four SW pumps CCF of the-EDGs, failure of the operators to use the SRVs, and CCF of the SRVs.
The IPEEE is scheduled for submission on June 28, 1994.
C.
Core Damana Precursor Events On the_ basis of the precursors identified by ORNL for 1991 and 1992 (NUREG/CR-4674, vols.15 thru 18 SPSB did not identify any precursor events for the unit that have a c)o,nditional core damage probability of IE-5 per year or greater.
The following event has been classified as a "Significant Event" for the performance indicator program. From May,1992, until March 1993 Cooper continued to o>erate with RCS leakage, at a rate of approximately 0.4 gpm, tirough both-isolation valves of the shutdown' cooling suction line.
This rate was sufficient to require the operators to establish a relief path from the suction line to the ECCS keep-filled system.
During.the March,1993_ refueling outage - the licensee disassembled and inspected both valves (for the first time) and found cracks in the-seats and discs.
SPSB reviewed this event for its implications with respect to interfacing system LOCA.
It is not possible to calculate a conditional core damage probability for this event since there is no means available to detennine the probability of failure for the-suction isolation valves during the period -of-interest at Cooper, given the degree of leakage observed and cracks found.
If Cooper had experienced gross failure of the RHR suction line isolation valves the event would have been highly risk Therefore,, the physical condition of the plant may or significant.
may not have created a significant level of risk.
However, the
___ _ _ _
. COOPER PRE-DECISIONAL actions of the licensee indicated a lack of appreciation for the risk associated with an Interfacing Systems LOCA.
The following event was classified as an " Event of Interest" for the Performance Indicator Program. On 11/8/93, during a test of both EDG output breaker autoclose permissive relays, the contacts failed to close at the required sNpoint, investigation determined the cause to be due to miscalibration five months earlier, it was later determined that the EDGs would not have been affected by the relay miscalibrations during a loss of offsite power event that required them to start and immediately tie onto the safety buses. However, the output breakers would not hcVe automatically closed if offsite power were initially available and then subsequently lost after the EDGs were running in standby mode. The output breakers for the EDGs could have been manually closed by the operators in the control room.
An initial ASP evaluation of the event modelled both EDGs failed for a five month period with operator recovery credit and calculated a conditional core damage probability (CCDP) of 5.3E-5.
This CCDP is conservative since the EDGs would only have failed under the scenario described above.
VII.
ENFORCEMENT HISTORY (Since June 1992) 3/93 CIVIL PENALTIES - The action was based on two Severity Level 111 violations associated with: (1) providing inaccurate information to the NRC in res)onse to a Notice of Violation, and (2) the failure to ident'i fy and correct a potentially significant l condition adverse to quality, after the 1992 discovery of a strainer that had been left in a safety system since initial start-up.
Civil penalties were issued to emphasize the licensee's need to improve its problem identification and resolution programs. ($200,000) 10/93 civil PENALTIES - The action was based on three Severity Level 111 violations associated with: (1) several violations of 10 CFR 50 which collectively indicate a breakdown in the licensee's corrective action program; (2) the failure to maintain the containment hydrogen / oxygen analyzers in an operable condition; and (3) the failure to include the service water and reactor equipment coaling systems in the inservice inspection program since initial plant ugustions. Civil penalties were issued to emphasize the significance that the NRC attaches to these violations and the importance that the NRC attaches to NPPD's efforts to resolve deeply rooted and fundamental weaknesses in employee attitudes toward identifying and resolving problems.
The civil penalties were $75,000, $75,000 and $50,000 respectively.
,
. r.00PER PRE-DECISIONAL 3/94 ENFORCEMENT CONFERENCE - Two Severity Level IV violations were issued for inadequate procedures and weaknesses in the licensee's corrective program.
PENDING (EA 94-018) - Based on possible breakdown in the control of licensed activities, including procedural inadecuacies and technical specification noncompliances, fai' lures in configuration and design control, and two failures to control temporary modifications.
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! . _ - -
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. . . PRE-DECISIONAL . ' - Legend COOPER STATION 5*'* ' m i,,.., i,.~. we,.i.e, 91-2 to 94-1 Outerly Doto metwenng a N tDo.a m g g,, 3,,, gg m m R R R R
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l COOPER STAT 10N uew n > Peer Group General [lectric Pre-TM1 a.. , 91-2 to 94-1 frenos ord Denot.ons , Deviations From Plont Peer Group Self-Trend Medion Short Term Long Term DecWd incroved Wor te Better OPERATONS (including stortup) Automatic Sctcrns WNie Criticd.'- Ogffe
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13 . .. . . . . p- . .- ' . PRE-DECISIONAL COOPER l i I.
HISTORY The Cooper Nuclear Station (CNS) was first discussed at the June 1993 Senior Management Meeting ($2). The basis for concern was an apoarent declining level of performance.
In the previous two SALP periods, which ended in January 1992 and April-1993, performance declined in the areas of operations, radiological cortrols, maintenance / surveillance, engineering /tet.hnical support, emergency planninp, ly in the areas of self-assessment and the imp.'ementation of corrective and safety assessment / quality verificatiot.. Marginal performance, particu er actions for identified problems was apparent. In January and June 1994, the NRC , sent the licensee a trending letter requesting that appropriate remedial actions - he taken.
-The plant entered a forced, unplanned outage on May 25,1994, which continues to this date.
The plant shutdown was initiated because the emergency-diesel generators were declared inoperable due to concerns regarding their capability , to supply emergency electrical loads in postaccident conditions. Concurrent with the development of this issue and after the plant had been shutdown, the , inspection program identified that the control room emergency filtration system had been inoperable since 1989, in addition, the licensee discovered during design basis reconstitution efforts that the containment had been inoperable since 1974.
The root cause for the inoperability of these engineered safety feature systems was inadequate testing. The NRC subsequently issued escalated enforcement and proposed a Civil Petialty for these violations.
At the June 1994 SM, NRC managers recognized the need to obtain additional insight into the performance of CNS management and staff.
Accordingly AE00 established, based on Diagnostic Evaluation Team principles, a Special Evaluation Team (SET)toassessthelicensee'sperformance.
II.
CHANSE5-SINCE LAST SM Since July 1H4 a new station management team has been assembled.
This team includes new Site, Plant, Operations Planning and Scheduling, QA,- Safety Assessment, plant Engineering, Licensing, and Corrective Action Program (which includes the operational experience review program) Managers. In addition, new managers are being actively recruited for Corporate Engineering and Construction, and Onsite Human Resources. The capabilities of this new management team have not been fully assessed.
However,- some organizational and performance improvement actions have been made.
Historically, licensee management has noi accepted NRC assertions that management.
oversight and programs / processes at CNS were significantly im> aired.
In July 1994 the licensee initiated an independent self-assessment by industry peers to obtaIn an independent perfomance assessment-to confim the problems previously identified by the NRC.
This Diagnostic Self-Assessment , conducted July 25 concluded that there were s(DSA)ificant I>erformance through August 19, 1994, ign defic < encies that required resolution by the licensee. The major fincings of the.
DSA included: (1) corporate and station management did not foster high standards . _ _ _
, " COOPER PRE-DEC1510NAL of perfomance; (2? weaknesses existed in the licensee's long-range planning; management anc quality assurance oversight were not effective; and testing, configuration control, and corrective action programs were tcient.
Substantial inspection activity has bun performed and insight has been ained ' into licensee perfomance'since the last SM.
The region initiated en anced resident inspector coverage and performed two major team assessments.
From August 15 through October 7,1994, the NRC SET evaluated licensee perfomance and
' assessed the independence and rigor of the assessment processes and findings of the DSA. The SET held a public exit muting on November 17,1994. The SET found that the DSA was an' effective and comprehensive assessment, which reached substantive conclusions that were supported by the NRC's independent assessment.
The SET's findings, that closely paralleled the DSA's findings, included:and direction n (1
management did not provide the leadership (2) major programs and processes were n corporate-wide standards of performance; istent and effective accomplishment of l poorly defined and did not ensure the cons program goals and objectives; and (3 independent oversight and self-assessment were not effective in monitoring ong)oing activities for detecting deficiencies . or for ensuring that identified deficiencies were resolved. As a result of the ! DSA and the SET, senior licensee management recognized that problems and future challenges exist at CNS.
Confirmatory Action Letters-(CALs) have bun issued to address the specific hardware concerns associated with the emergency diesel generators and associated electrical distribution system, control room envelope, and containment , penetrations. The CALs also confirmed the licensee's agreement to evaluate its , operational experience and testing programs. A Demand For Infomation (DFI) was issued to determine whether the Commission could have reasonable assurance that, in the future, the licensee would conduct Station Operations. Review Committee (SORC) meetings and other activities in a manner which would assure plant safety and compliance with NRC regulations. A DFI was also issued to each individual -- holding a position on the SORC.
These DFIs were issued as a result of an invest'gation performsd by the Office of Investigations to review the apparent carel(ss disregard of the Technical Specification (TS) requirements for secondary containment.
The NRC established a Restart Panel, per Manual Chapter 0350, and developad L action plan for independent verification that the itcensee has adequately addressed issues prior to approval of plant restart.
The issues requiring resolution prior to restart ares the efficacy of the operational experience review program; the effectiveness of management's internal review; the adequacy of plant-wide surveillance testing; lectrical distribution system testing; configuration con identify and resolve deficiencies; e control - room envelope operability; control of containment integrity; effectiveness of the now management teamy and control of the cooldown rate.
These-issues were discussed with the licensee and mutual agreement has been . reached regarding items on the restart list. Emergent items will be added at the - ' discretion of the Panel.
Under the direction of the new management team, the licensee has developed a i comprehensive Restart Action Plan wh< ch includes a methodology to identify the L actions to be completed prior to plant restart. The NRC Restart Panel and the
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- e
,. PRE-DECISIONAL COOPER licensee have met in a public forum and have, in principle, agreed on the restart issues; however,- the issues may change based on further reviews conducted by the licensee and the NRC.
The licensee has initiated integrated planning at the corporate level to address the short. and long-ters issues that need to be resolved.
The licensee had previously issued three different improvement plans te address performance and correct weaknesses; however, these plans have been abandoned by the new management team. The licensee plans to issue a new comprehensive plan, to be known as the Performance Improvement Plan, to address the actions to be taken to correct the ongoing problems at CNS.
!!!. FW URE ACTIVITY 1he new licensee management team has acknowledged weaknesses in the custom TS for Cooper. Prior to restart, the licensee plans to establish interim administrative controls to address-weaknesses -in the TS for control room pressurization, instrument surveillances, and EDG operability requirements.
The licensee is currently evaluating options for upgrading the Cooper TS, but has not committed to adopting the BWR/4 Standard TS.
The NRC Restart Panel will coordinate the inspection efforts to verify that the identified restart issucs have been satisfactorily addressed prior to approval of plant restart. As a minimum, these inspection efforts will include augmented resident inspection coverage, program reviews of the identified program weaknesses, and a modified Operational Readiness Assessment Team inspection.
As of December 15, 1994, only one license amendment needed prior to restart was under review by the staff: a proposed change to increase the minimum pressure at which the HPCI system is required to be operable.
However, the licensee is reviewing surveillance requirements with frequencies of "once/ cycle" and "once/ refueling outage", to detemine if there is a need to request NRC approval for any schedu' ar extensions due to the unforeseen length of the current forced outage. The previous refueling outage ended in July 1993 and the next refueling outage is not scheduled until the Fall of 1995.
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~ ... " ' ' _ _ _ _ _ _ _. _ _
_. _. _ _ _.. -. _ _ _ _ _ _ _... _ _ _ _ _._ . . PRE-DEcl$10NAL COOPER DATA SUMMARY I.
OPERATIONAL PERFORMANCE A.
Scram Stannary, , None.
B.
Sienificant Goerator Errors None.
C.
Procedures - Significant deficiuncies have been identified with station r surveillance procedures. Several deficiencies have been identified where surveillance procedures were not sufficient to demonstrate Technical Specification operability.
II.
CONTROL R00N STAFFING A.
m":r of Licensed coerators l
80 LIRQ IQIAL l
14
46 B.
m":7 and Leneth of Shifts ' Six, 12-hour shifts C.
Role of STA The STAS at Cooper Nuclear Station are on duty for a 24-hour rotational period.
They are not assigned-to an operating crew; however, they do receive training with a specific shift crew. STAS do not hold a senior reactor operators license.
The STAS primary duty is to act as an accident prevention and mitigation advisor to the shift supervisor. The licensee is considering placing STAS in - the normal shift rotation beginning in January 1995.
D.
Reelification Prearam Evaluation A requalification program evaluation' conducted in December 1993 resulted in a satisfactory rating for the program.
The next requalification program evaluation is scheduled for November 1995.
,
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. . PRE-DECISIONAL COOPER !!!. PLANT-SPECIFIC INFORMATION A.
Plant-smecifie information Plant Cooper Nuclear Station (CNS) ' Nebraska Public Power District (NPPD) Owner . ReactorSupplier/ Type GE/8WR Capacity, MWe 778 AE/ Constructor Burns & Roe Comercial Operation Date July 1, 1974 B.
Unteue Desian Information containment: Mark I, with a hardened vent Emercancy Core Coolina System: Two loops of low pressure core spray, two loops of low pressure coolant injection, one high pressure coolant injection - system, one reactor core isolation _ cooling system, and an automatic depressurization system.
AC Power Five 345-kV lines, one 161-kV line and one 69-kV line; two turbocharged, V-16, Cooper-Bessemer diesel generators.
DC Power: Four Class 1E batteries with 8-hour capacity (and four batterychargers),two125-voltandtwo250-volt.
IV.
510NIFICANT MPAs OR PUNT-UNIQUE 118UES MPA B-125 (Generic Letter 94-M, IGSCC of Core Shrouds in BWRs): In its 26, 1994, response to the subject GL, NPPO indicated that it will August perform inspections of the Cooper core - shroud at the next refueling currently scheduled for the Fall of 1995.
In the safety outage, assessment incleded as part of the response, NPPD concluded that the - operation of Ccop3r until the next refueling outage would pose no undue risk from tre.wtsntial for core shroud cracking.
In support of that conclusion, NPPD maintained that the core shroud has a relatively low susceptibility to cracking due to the maintenance of good water chemistry at Cooper, applied 1Ws to the core bhroud during design basis even.. are low, the plant-specific minimum ligament required to maintain structural margins is 7% of wall thickness, and design margina are maintained even witi significant shroud cracking such that safety system effectiveness and core coolable geometry are ensured. Further, the Itcensee's probabilistic safety assessment concluded that the estimated overall incremental core damage frequency is less than IE-6-per year, assuming a 360' -circumferential through-wall crack for a variety of postulated accidents.
The staff has reviewed the licensee's submittal and concluded that it provided adequate justification for plant operation until the next - refueling outage.
MPA B-111 (Generic Letter 88-20, Individual Plant Examination): The licensee submitted the IPE for Cooper on March 31, 1993. The Cooper IPE consists of a Level 1 and 2 PRA. The estimated mean core damage frequency is 7.97E-5 per year. On October 21, 1994, the staff issued a Request for
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PRE-DECISIONAL COOPER Additional Information (RA1); the titenste's response to the RAI is expected by December 21, 1994.
The staff's rulew is scheduled to be completed by March 1995.
The MPA B-110 -(Generic Letter 89-10, MOV Testing and Surveillance): , licensee is preparing an extension request for the completion of their MOV dynamic testing program.
They had previously committed to complete the However, due to the extended refueling outage program by January 1,1995.
in,993 and the current forced outage, the next refueling outage has been rescheduled for Fall 1995.
f V.
STATUS OF THE PHYSICAL PLANT A.
Eggbl== Attributed to Aetne s None.
B.
sOther Hardware issues See attached risk impact study on hardware issues.
, t VI.
PRA ' A.- ERA Insiehts ! Cooper is a BWR-4 with a Mark I containment. BWR PRAs indicate that i station blackout is a major contributor to core damage frequency.
Offsite power for Cooper is supplied from several 161 kV and 345 kV lines that feed into the start-up transformer, and a 69 kV line that feeds into an. emergency transformer.
The 69 kV power source , supplies emergency ' oads only.
The 69 kV offsite power source previously hac a poor record of spurious failures due to lightning After a safety system features inspection (SSFI) revealed strikes.
voltage problems on the 69 kV line, a new substation was added to help control the power. - Since December 1992, the 69kV power source has been reliable. A complete loss of offsite power event has never occurred at the site.
The emergency diesel generators (EDGs) require control-air to maintain a set engine speed and provide protective trip functions.
If control air is lost, the EDGs will shut down.
Cracking of instrument air tubes has occurred due to vibration resulting in , Relocatitm of engine mounted instruments has diesel engine trips.
apparently rectified the situation in that for approximately the . ': ? past two years there have been no distel-engine trips-because of In the event of a station blackout, the 250 Vde and that situation.
125 Vdc batteries have the capacity to accommodate the loads for a At Cooper, both the air duration of 8 hours without load shedding.
system compressors and receivers are classified as essential.
Published PRAs provide a strong ' indication that service water ' systems (SWS) are risk significant.
In the past. Cooper has experienced microbiologically induced corrosion (MIC) in certain
.,
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_______ __ . PRE-DECISIONAL COOPER sections of piping associated with the SWS (radiation monitor sample line) as a result of stagnant or low flow conditions.
The entire SWS was reviewed to identify sections of piping subject to these same conditions. All identified sections of piping were inspected and no similar conditions were found.
At Cooper, the SWS was not originally designed as an ASME Code Class 3 system.
Although the SWS is included in the IST program, it has not been included in the 151programinaccordancewiththeprovisionsof10CFR50.55a(g).
Therefore, the staff has suggested to RES that the treatment of the SWS failure rates should be evaluated carefully during the IPE review process.
The licensee plans to include the SWS in the ISI program at the 1995 refueling outage.
Also, in 1994, excessive silting was noted in the SWS as well as at the end of the SWS intake structure.
The licensee is taking action to address silting concerns, including dredging the river bottom near the intake structure, and designing weir wall modifications to reduce silt , buildup.
B.
PRA Profile in response to Generic Letter 88-20, the licensee submitted an IPE for Cooper on March 31, 1993. The IPE was performed by a team made up of licensee staff and contractor personnel.
In the IPE submittal, which contains a Level 1 and 2 PRA, the estimated mean core damage frequency is 7.97E-5 per year.
The IPE review is expected to be completed in February 1995. The IPE submittal does not provide a summary of the risk profile in terms of initiating events and sequence contributions to core damage frequency. It does arovide a risk profile in tems of accident type, which is presented >elow.
Accident Tvoe % of Core Damnae Freauency Station Blackout 34.8% Transient Induced LOCAs 30.3% Loss of Coolant Injection 18.1% Loss of Containment Heat Removal 10.9% ATWS 4.9% LOCAs 0.9% Fast Containment Failures 0.1% Because the IPE was sumarized in terms of accident type, a coarse review of the IPE by the staff was performed to try to categorize the risk profile in terms of initiators and sequence contributors to core damage frequency for comparison purposes. On the basis of this review, it appears that the loss of Containment Heat Removal category refers to sequences initiated by loss of Service Water.
The Loss of Coolant injection category appears to include sequences involving any type of transient with no injection systems of the reyirbd pressure available.
The most dominant contributors to accident sequences that lead to core damage were found to be failure of the EDGs to continue to run,
____ _ __
--__-_ _ ____ - _ _ __ . COOPER PRE-DECISIONAL l mechanical failures of the HPCI and RCIC systems and RCIC turbine, ' comon cause failure (CCF) of all four SW pumps to run, CCF of the EDGs, failure of the operators to use the SRVs, and CCF of the SRVs.
The IPEEE is scheduled for submission in December 1995.
C.
Core Damace Pr'ecursor Events On the basis of the precursors identified by Oak Ridge National Laboratory (ORNL) for 1992 and 1993 (NVREG/CR-4674, vols. 17 thru 19), the staff did not identify any precursor events for the unit that have a conditional core damage probability of IE-5 per year or greater.
The following event has been classified as a 'Potentially Significant Event Considered Impractical to Analyze" in the 1993 NVREG/CR-4674, and as a "Significant Event" for the Performance Indicator Program. From May 1992 until March 1993, Cooper continued to operate with RCS leakage, at a rate of approximately 0.4 gpm, through both isolation valves of the shutdown cooling suction line.
This rate was sufficient to require the operators to establish a relief path from the suction line to the ECCS keep-fill system.
During the March 1993 refueling outage, the licensee disassembled and inspected both valves (for the first time) and found cracks in the seats and discs.
The staff reviewed this event for its implications with respect to interfacing system LOCA.
It is not i possible to calculate a conditional core damage probability for this event since there is no means available to determine the probability of failure for the suction isolation valves during the period of interest at Cooper, given the degree of leakage observed and cracks found.
If Cooper had experienced gross failure of the RHR suction line isolation valves, the event would have been highly. risk significant. Therefore, the ahysical condition of the plant may or may not have created a sign 1ficant level of risk.
Eowever, the actions of the licensee indicated a lack of appreciation for the risk associated with an interfacing systems LOCA.
The following event was classified as an ' Event of Interest" for the Performance Indicator Program. On November 8, 1993, during a test of both EDG output breaker autoclose permissive relays, the contacts failed to close at the required setpoint. Investigation determined the cause was miscalibration five months earlier.
It was later determined that the EDGs would not have been affected by the relay miscalibrations during a loss of offsite power event that required them to start and immediately tie onto the safety buses. However, the output breakers would not have automatically closed if offsite power were initially available and then subsequently lost after the EDGs were running in standby mode. The output breakers for the EDGs could have been manually closed by the operators in the control room.
An initial accident sequence precursor (ASP) evaluation of the event modeled both EDGs failed for a five month period with operator recovery credit and calculated a conditional core damage I
. _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ -
- - - - - - _ - _ - - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. . PRE-DECISIONAL COOPER probability (CCDP) of 5.3E-5. This CCDP is conservative since the EDGs would only have failed under the scenario described above.
The following event was classified as a 'Significant Event' for the Performance Indicator Progrtm.
On May 25,1994, both EDGs were declared inoperable when load shedding of all nonsafety-related loads from the' vital buses could not be verified. The load shedding could not be verified due to preconditioning during past surveillance tests by removing certain nonsafety-re' ated loads from the vital buses prior to the EDG testing.
Thus, under worst case loading conditions, the EDGs may have been inoperable.
The worst case loading conditions are expected to exist during a LOOP /LOCA which has a very low frequency of occurrence.
Subsequent testing demonstrated that not all nonsafety-related loads would have shed.
Calculations by the licensee showed that a margin existed for the EDGs to be operable if those loads had remained tied onto the buses.
Although the staff could not independently confirm the licensee's calculations, the diesel manufacturer verified that the diesel could be operated for brief periods without damage at loads substantially above the maximum design rating. On this basis, the staff concluded that the diesel generators would probably have performed their intended function even if nonessential loads had not been automatically shed from the emergency buses.
The following was classified as an ' Interesting" event in the 1993 NUREG/CR-4674. On February 25, 1993, a design basis review of the SWS and the reactor equipment cooling (REC) system identified that Division I SW supplied the Division 11 REC heat exchanger and Division !! SW supplied the Division I REC heat exchanger.
Given the design errors found, had Cooper experienced a LOOP along with a failure of EDG-1, nonessential SW and REC loads could not have been isolated by remote means and the MOV supplying critical loop "A" REC loads would not have opened.
Consequently, for the conditions assumed, adequate cooling to the operable EDG, the functional REC het.t exchanger, the RHR SW booster pump, and other loads could not have been assured.
Similar concerns exist for the failure of the Division II EP. D.
Exnanded PRA Insichts Conclusions on the Coooer Nuclear Station Overall Risk imonet of the Hardware issues Reoorted in 1994 The events analyzed include Safety System Failures (SSFs) in the Performance Indicator Program as well as start-up issues.
For the
' 11 events analyzed, hardware failures were observed or had the .! potential to fail.
In addition to the events, the MOV issues were reviewed.
The event description, safety significance, and risk +4 T< impact are addressed in the following pages. The conclusions are ' stated below.
. -. ........
-.. _ _ _ _.
- COOPER PRE-DECISIONAL HARDWARE !$$UES Distribution of Hardware Issues Hardware issues were distributed among the following systems:
Emergency Diesh1 Generators (EDG) > High Pressure Coolant Injectton (HPCI) l Reactor Core Isolation Cooling (RCIC) > , Core Spray (CS) lant Injection'(LPCI)
i Low Pressure Coo ' Service Water (SW) l lh Reactor Equipment Cooling (REC) . Standby Liquid Control ($LC) l Thus, the hardware issues are not conttined to a particular system.
Sinnificant Events on Nay 25, 1994, both EDGs were declared inoperable because load shedding of all normal loads prior to starting the diesels during > surveillance had not -been achieved.
This was classified as a Significant Event.
l Safety System Failures , i The number of SSFs in 1994 are above the BWR industry average. The distribution of SSFs in 1994 are as follows: Control Room Ventilation (1) l Control Room Emergency Filtration (1) Standby Gas Treatment / Control Room Emergency Filtration (1) Emergency Diesel Generators (1) High Pressure Coolant Inject <on (2)- Nethod of discoverv l ' About 50% of the.iardware issues were found through surveillance testing or by review of surveillance test requirements.
' This method of discovery for the HPCI problems is consistent with the results published in NUREG/CR ' Aging Study of Boiling Water Reactor High Pressure Injection Systems-(DRAFT)' which determined . that the majority of HPCI failures were found through testing and inspection at-BWRs.
The EDG issue was identified by the NRC.
The other issues were identified by the licensee through design reviews and walkdowns.
, '
. - . . . . . .. . .... . .. .
. . . . PRE-DECISIONAL COOPER System Testina System testing in the past appeared to be inadequate.
Past surveillance testing practices were observed to not adequately ' demonstrate EDG and CS system reliability under-certain accident conditions. A)so, as part of the design basis reconstitution of the . primary containment, the licensee discovered during walkdowns that several containment penetrations had never been tested by local leak or as a boundary during the integrated leak rate rate testing (LLRT)In addition,d in the ASME Section XI inserv ILRT).
certain Reactor Equipment Cooling testing (d never been include piping ha inspection program and had been found to be leaking.
MOV Program , The Cooper MOV program is considered an acceptable GL 8g-10 program, but is considered the weakest in Region IV.
The majority of MOV * issues are programmatic and procedural. The discovery of potential overthrust conditions created in 1986 by modifications to 10 "sive actuators is an example of a recent problem correction, rather than a problem creation.
M0V problems seen in the events were of a control and timing nature.
The 'A* -LPCI train outboard injection valve, though, experienced - some leakage due to a foreign material exclusion problem.
RISK IN518 HTS ' Station Blackout (580) is a major contributor to the Cooper core damage frequency (CDF).
The EDG operability issue due to past surveillance testing preconditioning practices and the RCIC turbine trip throttle valve AC de>endency would be expected to slightly increase the 580 contribut'on to the CDF.
The IPE indicates that commen cause failure of all four SW pumps has a high risk achievement worth.
The observed silting in the river near the end of the intake structure would have been a common cause failure for the SW pumps at minimum river levels.
The IPE indicates that the HPCI system failure to start and failure to continue to run are key contributors to the CDF. The sensitivity studies indicated that the HPCI system CDF contribution could be-reduced if certain system modifications were implemented; however,the implementation of those modifications would not have prevented the potential HPCI system inoperability due to the HPCI system hardware issues observed in 1994.
- ~ VII. ENFORCENDfT HISTORY-3/g3-CIVIL PENALTIES - The action was based on two Severity level 111 violations associated with: (1) providing inaccurate information to the NRC in response to a Notice of Violation; and (t? the failure to identify and correct a potentially significant condition adverse to
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. PRE-DECISIONAL COOPER quality, after the 1992 discovery of a strainer that had been left in a safety system since initial plant start-up.
Civil Penalties were issued to emphasize the ~ licensee's need 'to improve its >roblem identification and resolution programs.
Although mitigat' on was appropriate for the licensee's previous good performance regarding the accuracy of submitted information, it was offset by the escalation for'NRC identification and the licensee's failure to act upon information which indicated that its submission was inaccurate.
Nitigation of the Civil Penalty was appropriate for licensee identification, but was offset by the escalation for failure to act upon prior opportunities to identify the presence of strainers and poor licensee perfomance in the area of corrective actions. The total Civil Penalty was $200,000.
10/93 CIVIL PENALTIES - The action was based on three Severity Level III.
violations associated withs (1) several violatior,s of 10 CFR 50 which collectively indicate a breakdown in the licensee's corrective action program; (21 failure to maintain the containment hydrogen / oxygen analyzers in an operable condition; and (3) failure to include the service water and reactor equipment cooling systems in the inservice inspection program since initial plant operations.
Civil Penalties were issued to emphasize the significance that the NRC attaches to these violations and the importance that the NRC attaches to NPPD's efforts to resolve deeply rooted and funnmental weaknesses-in omsloyee attitudes toward identifying and resolving problems. The CLvil Penalty associated with the corrective action The Civil program was escalated for NRC identification. ($75,000) lyzers was Penalty associated with the inoperable hydrogen / oxygen ana i escalated for NRC identification and multiple licensee opportunities ' to identify the problem but mitigated for the licensee's corrective . The Civil Penalty associated with the failure to actions ($75,000) ice water and reactor equipment cooling systems in.. include t'e serv n the inservice inspection pr ram was not adjusted ($60,000). The total Civil Penalty was-$200, 00.
ENFORCEMENT CONFERENCE - Two Severity Level IV violations were 3/94 issued for inadequate procedures and weaknesses in the licensee's
corrective act.an program.
! 4!94 ENFORCEMENT CONFERENCE - Several Severity Level IV violations were issued-- concerning the failure to follow plant procedures; the , failure to provide required quarterly training for the fire brigade; and the failure to maintain configuration control.
, ' 11/94 DEMAND FOR INFORMATION - The staff issued ~a Demand For 1aform related - to licensee management. personnel involving careless-requirements governing the establishment of . disregard - for TS secondary containment prior to the movement of loads that could potentially damage irradiated fuel.
, 12/94 CIVIL PENALTIES AND ENFORCEMENT DISCRETION ~ This action w
' on three-inspections conducted from Nay 3,1994, to August 12, 1994.
that' identified eight violations that were subsequently grouped into j >
. . . .. a .. .. . . ~. -.
. COOPER PRE-DECISIONAL three problass; each problem being categorized at severity Level !!!. The first problem consisted of violations related to the primary containment system and failures to maintain operability, adequately test, and maintain design control of the system.
The second problem involved violations associated with 480 volt and 4160 volt critical. buses and failures to adequately test and maintain system operability.
The third problem consisted of violations pertaining to -the control room emergency filtration system and failures to maintain operability and to adequately test the system.
To emphasize the need for licensee senior managers to identify and undertake. sustained actions to improve the overall level of safety performance at Cooper Nuclear Station, a Civil Penalty was issued for the three Severity Level !!! problems described above. Although application of the Civil Penalty adjustment factors could have.
resulted in a significantly higher civil penalty, discretion was exercised to set the total Civil Penalties at $300,000DIscra$100,000 or for each of the three Severity Level III problems.
tion was-exercised because of the licensee's initiative to shut down the urit until successful implementation of an improvement prograa to address underlying root causes of performance deficiencies, the licensee's commitment not to restart the plant without prior NRC approval,-and the significant changes in licensee's manaqement oversight of site activities.
This action was also the sub;ect of Commission paper SECY-g4-285. The total Civil Penalty was $300,000.
<
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. .. _ - - - - - - - - - COOPER MOST RECENT SALP RATINGS
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' COOPER STATION Refwe6ng k (per0L'on Q NJetry Avg 17e'd h tDow9 M 91-4 io 94-3 ourterly Doto ,,,, g,,,,, g, g,,,, gggg _ s,. -. tse R R R R W- ' ** - 3 D 52-v y>- 3
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e ., , MSRA$tA PtSLIC POWEE 915TRICT COOPEE STAIION P8E510ENT & CEO . Senald W. Wattles (462) M3-55% W Nu[LEst Gay R. More .- (GeZ) M 3-5518 SITE mansEn l sivi5las muusta sivl5 Ins sususta arvistas maasta tuhLITY ASSURAstE nut. EME*INE. & CONST.
NUELEAR SUPPORT John M. Meeller (7/94) (402) 825-5769 fichard A. Sessess (S/94) Ele C. Waldee (Actieg) Doold A. W itsee .* (402) 825-5599 (402) M3-5349 (10/94) (402) 5E15401 " 58. WWELEAR SIVISIGE SEE.
PLANT $2. PJussEn 5METT A55E39EWT funnsta SITE SUProsT Reyesed G. Jones (9/94) John T. Iterrea (18/94) Espese Mace (18/93) (402) 825-5775 (402) 825-5233 (est) 825-5324 OPERATIDE5 IWWWsEE euCLEAR TRAleIK fuGAEE9 muCLEAA LICIW51 K & Peel J. Derite (11/94) J. W. Dettee SMETT 804MGER EeGINEteIK IuAAEER 9ebert C. Godley (7/94) - Jaaes W. Geesese (9/94) (402)825-5819 PJGIOLCEICAL ftWeeGER _ J. v. Sayer . I?f2If*4 _
l . . COOPER PRE-DECISIONAL EMERGENCY DIESEL GENERATORS EVENT / DESCRIPTION SAFETY SIGNIFICANCE RISK IMPACT 5/25/94 Both EDGs de-The concern was that if Small CDF increase ex-clared inoperable the additional loads pected, had remained on the On 5/25/94, the buses, then neither of Since the EDCs would licensee declared an the EDGs would be capa-have been operable, the NOVE after determining ble of providing suffi-increase in th CDF that both EDGs were cient power to vital would be small. The inoperable. Cooper equipment, small increase would be stayed in the NOUE for attributable to opera-56 days.
Thus, EDG operability tor actions. The was questionable under licensee had concluded The licensee discovered worst case loading con-that operators would that past surveillance ditions such as those need to manually shed tests of the EDGs experienced during a loads if the maximum failed to verify that LOOP /LOCA scenario.
loading on the EDGs was all loads were shed greater than the con-from the 480V and 4160V The licensee submitted tinuous rating of 4000 vital buses given an a calculation to show kW after two hours.
undervoltage condition that even with tho non-on these buses. This safety-relsted loads verification had not connected to the buses, , been accomplished in the EDGs would have ,pi.st tests due to the been operable. The preconditioning prac-staff concluded that tice of removing cer-the EDGs would have tain nonsafety-related perfcrmed their loads from the buses intended function, prior to testing. Sub-sequent testing to verify proper load shedding revealed that not all nonsafety-re- - lated loads would have ,shed.
References: LER #94-009-00 NRC IR 50-293/94-16 \\
__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_ __ . . .. PRE-DECISIONAL COOPER HIGH PRES $URE COOLANT INJECTION EVENT / DESCRIPTION SAFETY SIGNIFICANCE RISK IMPACT EN #26993 The HPCI steam stop The associated risk is 03/25/94 valve is required to the potential for in-open to establish a creased HPCI system HPCI declared inopera-- path for steam to the unreliability if hard-ble following a sur-turbine. The valve ware problems are not veillance test due to opening delay causes a found through surveil-the HPCI steam stop~ delay in the turbine lance testing.
valve opening in 51 start.
seconds. The required time to open is < 38 seconds per IST re-quirements.
LER #94-007-00 This condition could The HPCI turbine may 04/13/94-have lead to HPCI tur-become inoperable fol-bine bearing failure lowing a trip after HPCI was declared inop-due to loss of lube oli successfully starting erable following sur-cooling if turbine op-and running. The re-t veillance testing when eration had continued, covery is complicated the lube oil cooler If the condition was by the operator poten-pressure control valve not corrected by an tially failing to re-failed to re-open after operator and HPCI tur-attach the tubing. The the HPCI turbine had bine operation contin-risk depends on the tripped. The failure ued, the HPfl system duration that this con-of the valve was at-could have become inop-dition existed, tributable to a discon-erable.
nected tubing associat-ed with the valve con-troller.
LER #94-012-00 If the HPCI system were No risk impact.
07/08/94 to isolate at 127 psig, HPCI makeup would not The licensee noted a be available between conflict between the 113 psig and 127 psig, established setpoint However, sufficient for the HPCI low steam overlap makeup capacity line isolation pressure exists from the LPCI switch set.at 127 psig and the CS systems in and the TS operability this range.
requirement that the HPC'. system be operable at pressures > 113 psig.
' %
... _. l . . COOPER PRE-DECISIONAL ' REACTOR C0RE ISOLATION COOLING EVENT / DESCRIPTION SAFETY SIGNIFICANCE RISK IMPACT LER 194-018-00 In the event of a SBO, CDF increase expected.
08/20/94 ,RCIC provides cora cooling for the dura-RCIC would have been The licensee discovered tion of battery life.
unavailable during a that t.he RCIC Turbine If the RCIC Turbine SB0 if the Turbine Trip Trip and Throttle Valve Trip and Throttle Valve and Throttle Valve had (TTV) was powered by an had closed during an closed. This condition AC motor. This valve SBO, neither automatic would increase the Core should have been pow-nor remote manual reset Damage Frequency con-ered by a DC motor of the valve would have tribution from the SBO.
since the RCIC system been possible. Local The SB0 contribution is is designed to be inde-operator action would 34.8%. - pendent of AC power, have been required; however, no guidance on The second greatest CDF this function was in-contributor sequence cluded in SB0 proce-is: dures.
SB0, loss of HPCI due to loss of room cool-ing, loss of RCIC be-fore battery depletion, , failure to recover off-site power.
The AC dependency of the turbine TTV is not modeled in the IPE.
If tha-TTV were to close before battery deple- . tion, RCIC would be lost.
<
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COOPER PRE-DECISIONAL ! CORE SPRAY EVEN1/0ESCRIPTION SAFETY SIGNIFICANCE RISK IMPACT
LER #94-002-02 The function of the Excessive cycling of 02/01/94 minimum flow valves is the valves during mini- ' to provide minimum flow num flow operation con-Cycling of the CS mini-protection for the tributes to the CS sys-mum flow isolation pumps. Excessive cy-tem unreliability due valves or both trains cling could lead to to the potential to during minimum flow loss of minimum flow deadhead the pumps. An operation was cbserved, pump pretsetion.
NRC inspection conclud-The B loep ve % closed ed that the licensee's during surve11 D nce CS system testing did testing on Feb. 1, 1994 not confirm the capa-and on Apr. 27, 1994.
bility of the CS pumps - The A loop valve closed to operate in a minimum on July 23, 1994.
flow configuration for a full 30 minutes, as required for certain postulated accident scenarios.
LOW PRESSURE C0OLANT INJECTION EVENT / DESCRIPTION SAFETY SIGNIFICANCE RISK IMPACT EN #26948 This valve is normally Due to the redundant 03/16/94 o >en. In the event means of isolating the t1at the valve is need-LPCI injection line, The "A" LPCI train was ed to isolate the LPCI the risk of this event declared inoperable injection line, the is minimal, when leakage was dis-valve may not have ful-covered past the LPCI ly performed that func-Outboard Injection tion. There are three-Valve RHR-MOV-M027A.
other valves tatween Votes testing and an the outboard injection LLRT were used to con-valve and the reactor fim this condition.
vessel which could iso-late the line also.
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.us- . . .. . . . ' COOPER PRE-DECISIONAL , $ERVICE WATER EVENT / DESCRIPTION SAFETY SIGNIFICANCE RISK IMPACT EN #27971 At minimum river This event reveals a 11/01/94 1evels, sufficient potential connon cause < water would not have failure of all four SW Minimum design river been available to pro-pumps. The IPE indi-level assumed in the vide the required NPSH cates that connon cause USFAR has been invali-for the service water failure of the SW pumps dated by silting in the pumps, has a high risk achiev-river. The silting may ement worth, and that have been caused by the actions taken to reduce Missouri River flooding the frequency of the in 1993.
loss of all Service Water has a high risk reduction worth. The licensee waited approx-imately a year after the Missouri River flooding before taking action to reduce the potential common cause failure of the SW pumps ' by dredging the south-I ern end of the intake structure.
REACTOR EQUIPMENT COOLING SYSTEM EVENT / DESCRIPTION SAFETY SIGNIFICANCE RISK IMPACT-MR #4-94-0072 Potential for failure The risk from the actu-08/01/94 of the' REC system and al event was minimal subsequent loss of since the leakage was The licensee discovered cooling water to safety small and discovered a through-wall leak in related equipment.
before the cracking a 12" REC pipe. The worsened. The use of crack propagated the corrosion inhibi-through a weld. GE tor, however, increased' noted that sodium ni-the probability of a trate, a corrosion-in-REC pipe leak, hibitor used by the licensee from 1974-1980 contributed to the cracking.
i
muu mumm's r - - si
. ' : . . COOPER PRE-DECISIONAL LER #94-017-00 Potential for a REC The expected frequency EN #27666 piping containment by-of a RR line break is 08/09/94 pass path if a high very smell. The conse-energy line break oc-quences, though, would The licensee is curred inside contain-disable the REC system performing a reassess-ment, and create a contain-ment of a potential r.ent bypass pathway.
event in which the 8' REC piping in the dry-well adjacent to the RR pump discharge piping may be a sotential con-tainment sypass path.
As described in IN 89-055, the water in the return REC piping would be discharged out of the surge tank ' located in secondary containment if a high energy line break oc-curred inside primary containment.
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1
-~~ --- --- . . PRE-DECISIONAL ~ __ EVENT / DESCRIPTION STA28Y LIKID CONTROL
i.
LER #94-026-00 . SAFETY SIGNIFICANCE 10/09/94 The SLC system is de-RISK IMPACT signed to shutdown the In the event of an > The licensee discovere reactor if shutdown can-ATWS, control rods that the temperature od not be obtained with by the Alternate Rodcould also be the SLC piping was not f the control rods.
being maintained above temperatures lower than At Insertion System the TS limits for the the TS limits, the control rods can.
' If concentration of sodiu sodium pentaborate con-inserted, SLC can be not be pentaborate in the sysm centration decreases used.
tem.
Also due to crystallization.
head was no,t heatthe pump Too low of a concentra-The ATWS accounts for traced and insulated in the rtion would not bring 4.9% of the CDF accordance with the If cations.esign specifi-down.eactor to shut-the SLC pump ope.
system d At the minim ty is affected by therabili-room design temperaum expected crystalliza-ture lieve,s that the SLCthe licensee be-tion under co temperatures,ld room system would be opera-ATWS CDF contributionthen the ble due to a higher may be increased.
solution concentration in the SLC tank sinceAlso reviews of c the tank is heated by shrou,d cracking reore internal heaters, and sponses to GL 94-03 the pumps would be ableindicate that SLC is to perform with the important given that expected crystalliza-ome worst case scenar-s ion in the piping, t ios may affect the abi-l ity to insert control ods.
r Cooper plans on performing core shroud inspections at the next refueling outage.
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_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. b- .? l. ' COOPER NUCLEAR STATION - NRR STATUS UPDATE JANUARY ll, 1995 BACKGROUND: Unit shut down since May 25, 1994 (230 days).
Two CAls remain open.
- Licensee DSA report issued 9/6, NRC SET report,11/29.
E00 attended SET
and DSA public exits, 11/17.
Staff Actions Memo issued 12/22/94.
Restart Panel and Action Plan formed, in accordance with IMC 0350.
- 5 internal meet.ings, 3 public meetings at site.
12 NRC restart issues identified, 34 by licensee (including all NRC issues).
ENf0RCEMENT STATUS 2 Proposed $300K CP and NOV issued 12/12/94 for violations involving . inadequate testing of the electrical distribution system, control room envelope and containment integrity.
Licensee's response pending.
Licensee responded on 12/12/94 to the NRC's 11/10/94 Demand for
Information concerning potential 50.9 and TS violations, and poor performance of the Station Operations Review Committee.
OE, NRR and Region IV will reach a consensus on further action shortly.
Also under consideration are a number of cther potential 50.9 violations; in 1993, the licensee had received a $100K CP for 50.9 violations.
ONG0ING ACTIVITIES AND ISSVES: Current schedule for restart is January 29, 1995; may be delayed due to . MOV testing in pro 9ress.
Licensee to static test all remaining MOVs, with completion of dynamic testing during Fall 95 RF0.
At the January 5,1995 public Restart Panel meeting, the Panel expressed
concerns over delays in receiving licenree closeout documentation.
These delays could impact Pegional inspection and NRR review activities.
A two week, Region-led restart team inspection is currently scheduled for January 16-27, with a final Restart Panel meeting planned to
coincide with the ex t meeting for that inspection.
i 4 licensing actions needed to support restart; 3 late submittals. TS - changes for HPCI LP setpoint, LC0 definition (GL 87-09); ISI relief request on HPCI turbine exhaust weld, MOV program schedule extension request.
In addition, CR fan upgrade TS change to be issued by restart.
3 issues identified by the licensee as not requiring formal NRC action = (fire protection program discrepancies, IST reliefs and cyclical surveillances). Will be reviewed by NRR to confirm the licensee's positions.
Information on two of these items has not been provided ye ___-____ l . OWER: 8 of 10 key managers below VP-Nuclear replaced since July 1994.
- Emergency Exercise 11/15/94 acceptable; I deficiency to State of
Nebraska for dissemination of information to public; 3 weaknesses: conflicting info to offsite agencies, weak scenario, errors in EPIPs for assessing EALs.
Initial Regional inspections of restart items indicate acceptable
performance, resolution of issues.
Licensee initiatives - replacement of Asco SSPVs, identification of
Appendix R discrepancies, Agastat relay maintenance, planned TS > improvement.
Positive licensee responses - MOV testing, staffing for OER review and
corrective action programs, i . .. . . . ... . ... a
. ~ ea , n, , ~ , \\ '6 PRE-DECISIONAL ' COOPER I.
HISTORY The Cooper Nuclear Station (CNS) was first discussed at the June 1993 SMM. The basis for concern was an apparent declining level of performance.
In the previous two SALP periods, which ended in January 1992 and April 1993, performance declined in the areas of operations, radiological controls, maintenance / surveillance, engineering / technical support, emergency planning, and safety assessment / quality verification. Marginal performance, particularly in the areas of self-assessment and the implementation of corrective actions for identified problems, was apparent.
In January and June 1994 and January 1995, the NRC sent the licensee a trending letter requesting that appropriate remedial actions be taken.
The plant enterad a forced, unplanned outage on May 25, 1994. The plant shutdown was initiated because the emergency diesel generators were declared inoperable due to concerns regarding their capability to supply emergency electrical loads in post-accident conditions. Concurrent with the development of this issue and after the plant had been shutdown, the inspection program identified that the control room emergency filtration system had been inoperable since 1989.
In addition, the licensee discovered, during design basis reconstitution efforts, that the containment had been inoperable since 1974, The root causes for the inoperability of these engineered safety feature systems included: an approach to testing to obtain the desired results instead of obtaining the as-found data, inadequate testing procedures; a lack of a questioning attitude regarding test performance and results; and a lack of managemerit oversight of the testing program. The NRC subsequently issued escalated enforcement and a Civil Penalty for these violations. On February 9,1995, after extensive management and program changes, the plant resumed power operation.
At the June 1994 SMM, WRC managers recognized the need to obtain additional insight into the performance of CNS management and staff.
Accordingly, AE0D established, based on Diagnostic Evaluation Team principles, a Special Evaluation Team (SET), which assessed the licensee's performance in October 1994.
The licensee also recognized a need for a self Diagnostic Self Assessment Team (DSAT) inspection.
In June 1994, the licensee selected an independent group to perform a third party evaluation of CNS.
Inspection findings identified significant weaknesses in management and overall pecformance, and program implementation. The SET inspection efforts validated the results of the DSAT.
II.
CHANGES SINCE LAST SMM Since July 1994, the licensee has replaced 8 of the 10 key managers below the Vice President-Nuclear.
The new management team successfully implemented the first phase of a three-phase performance improvement program (PIP) to prepare the plant for restart.
The NRC approved the PIP in February 1995.
The NRC CNS ' Restart Panel, established in accordance with Inspection Manual Chapter 0350, concluded that the licensee had adequately addressed the management weaknesses
_. _.... -.. . .. COOPER PRE-DECISIONAL ' that were identified as the root causes of the observed problems in programs and performance by the NRC Special Evaluation Team and the independent Diagnostic Self Assessment Team.
The panel reviewed extensive inspection data collected over several months, including the findings of the NRC restart team inspection conducted in January 1995. The restart team found that the area of operations was a relative strength and that corrective actions and management involvement and oversight were improved.
Improvements were also noted in the control of testing activities and in the surveillance testing and inservice testing programs.
Engineering was noted as an ares of relative weakness.
Direct observation of licensee performance by Region IV and NRR during startup and power ascension activities confirmed all of these conclusions.
In addition, the quality assurance organization appeared to take a more active role in monitoring )lant activities and the Station Operations Review Committee was considered to )e more effective in questioning issues brought for review.
The new management team's philosophy regarding the development of a safety culture that promotes a questioning attitude appears to be filtering down to working level personnel. The site manager and the plant manager are clearly the catalysts for change, and they also recognize the need for continued emphasis in this area.
The interim restart organization functioned effectively, with better work control and communication between departments. However, significant resources were expended during the restart effort in the use of overtime and contractor support, which the licensee plans to minimize now that the unit is back on line. Further observation of the licensee's implementation of Phases 2 and 3 of their performance improvement plan is necessary to assess whether the pace of recent improvements can be sustained.
The licensee encountered some difficulties during initial attempts at startup, which commenced on February 9,1995, including the failure of three safety / relief valves (SRW), the failure of two SRV tailpipe vacuum breakers, and the diccovery of potential problems with the operation of several MOVs due to vibration-induced movement of the valve stem protective caps.
The licensee took appropriate corrective action to resolve these problems and power 9scension and subsequent operation at 100 percent power have proceeded smoothly since February 19.
The physical plant has presented relatively few challenges for the licensee since the , resolution of the initial problems describe above.
On February 14, Mr. Ron Watkins, President and CEO of the Nebraska Public Power District (NPPD), announced his resignation effective April 1,1935. Mr. katkins has accepted the position of President and CEO of Old Dominion Electric Cooperative (ODEC) in Glen Allen, Virginia.
In a newspaper interview, he indicated that his reason for leaving was the attractive financial package offered by ODEC, and not for reasons related to Cooper's extended shutdown or regulatory issues. Mr. Robert L. Gangel, currently Vice-President for Finance and Administration, will assume the president's responsibilities until a permanent successor-is named.
On February 13, 1995, NPPD announced the reorganization of the Nuclear Power Group Engineering Department and the relocation of major engineering functions from-the General Office in Columbus to the CNS site.
Upon completion of the hJt. reorganization by October 1995, approximately 110 engineering personnel will be located onsite; a small transitional engineering group will remain in Columbus for the next year. The licensee believes that the reorganization will result in more effective engineering :Upport at CNS and in significant cost savings for th]e .
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/;d)tW . ' . I On February 13, 1995, NPPD announced the reorganization of the Nuclear Power Group Engineering Department and the relocation of major engineering functions from the General Office in Columbus to the Cooper site.
On May 1, 1995, Mr.
Philip D. Graham assumed the new position of Senior Manager of Engineering, responsible for - all NPPD-engineering activities at Cooper.
All current engineering employees were required to apply for positions in the new organization, which is scheduled to take effect on June 1,1995. As of May 8, three of four managers and 8 of 17 first-line supervisors had been selected; final selection of internal staff for the new positions was in progress.
Additional outside recruitment may be necessary to fill some supervisory vacancies and several staff positions, due to the departure of a number of current engineers who were unwilling to relocate.
The licensee is evaluating options for short-term engineering support through contractors or sharing of resources with other utilities.
When fully staffed, approximately 110 engineering positions will be located onsite; a small transitional engineering group will remain in Columbus through the end of the year.
NPPD believes the reorganization will result in more effective engineering support at Cooper and in significant cost savings for the utility.
> g..
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COOPER PRE-DECISIONAL utility. However, this decision has not been well received by the engineering staff; it is not clear how many engineers will.nake the move.
III.
FUTURE ACTIVITY The licensee's new management team has acknowledged the need for comprehensive improvement of the CNS custom technical specifications (TS). The licensee has selected a consultant to prerform a scoping study of the options for TS improvement, including conversion to the Improved Standard TS.
Based on the results of this scoping study, the licensee expects to develop a specific plan ' for TS upgrade by late summer 1995, with a comprehensive upgrade package to be , submitted in the fall 1996. The licensee has also held preliminary discussions with the licensees of a number of other boiling water reactor (BWR) Mark I plants to explore the potential for joint efforts toward TS improvement.
b In the interim, the NRR staff and the licent.ee have mutually agreed that several individual TS should be promptly revised, including TS for diesel generator operability, control room envelope surveillance testing, and logic system functional testing (LSFT).
The NRR staff and the licensee will continue to assess the need for additional license amendments to clarify or correct the existing TS on an individual basis, pending the licensee's final decision and implementation-of a' comprehensive TS improvement program.
. ,
The licensee is also conducting an extensive review of its surveillance test program, which will help to ensure that surveillances properly confirm equipment and system operability beyond TS requirements. Administrative procedures have been adopted for certain equipment surveillances to specify allowed outage times ' that are not e'xplicitly addressed in the current TS. These procedures provide a documented process for dealing with the lack of detail in some TS, in contrast l to the previous practice of implementing TS requirements based on informal and inconsistent interpretations.
_
r 3. . . ' ' COOPER PRE-DECISIONAL - . DATA $UMMARY' r ' I.
OPERATIONAL PERFORMANCE A.
Scram Summary None B.
Sienificant Operator Errors None C.
Procedures Significant deficiencies have been identified with station surveillance procedures.: Several deficiencies have been _ identified where surveillance procedures were not sufficient to demonstrate technical specification operability.
II.
CONTROL ROOM STAFFING-A.
Number of Licensed Oberatoti > 18.Q EQ llB.Q T0TAL c
-14
44 B.
Number and Lenath of Shifts Six, 12-hour shifts C.
Role of STA - The STAS at CNS are on duty for a 24-hour rotational period. They-are not assigned to an operating crew; however, they do receive-training with a specific shift crew.
STAS do not hold a senior reactor operatoes license. The STAS primary-duty is to act as-an accident prevention.and mitigation advisor-to the shift supervisor. : The licensee is currently training STAS for normal shift rotation, which began in January 1995.
D.- - Recualification Procram Evaluation A requalification program evaluation conducted in December 1993 resulted in a satisfactory rating for the program..The inspectors used guidance provided in NUREG-1021," Operator Licensing Examiner Standards," Revision 7, Sections 601 through 605. The licensed operator performance had improved since the last program evaluation.. The improvement in command and control and communications was noted.. Region IV will conduct an inspection in ' accordance with IP-71001, " Licensed Operator Requalification Program Evaluation," during the month of November 1995.
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COOPER PRE-DECISIONAL III.
PLANT-SPECIFIC INFORMATION
-A.- Plant.-Specific Information Plant Cooper Nuclear Station (CNS) Owner Nebraska Public Power District (NPPD) Reactor Supplier / Type GE/BWR Capacity, HWe 778 AE/ Constructor Burns & Roe CP Issued: 6/4/68 OL !ssued: 1/18/74 Commercial Operation Date 7/1/74 ' 8.
Unicue Desian Information , Containment: Mark I, with a hardened vent Emeraency Core Coolina Systems: Two loops of low pressure core spray, two loops of low pressure coolant injection, one high pressure coolant injection system, one reactor core isolation cooling system, and an automatic depressurization system.
AC Power: Five 345-kV lines, one 161-kV line and one 69-kV line; two turbocharged, V-16, Cooper-Bessemer diesel generators.
DC Power: Four Class lE batteries with 8-hour capacity (and four battery chargers), two 125-volt and two 250-volt.
IV.
SIGNIFICANT MPAs OR PLANT-UNIQUE ISSUES MPA B-125: Generic letter 94-03. IGSCC of Core Shrouds in BWRs In its-August 26, 1994 response to the subject GL, NPPD indicated that it will perform inspections of the CNS core shroud at the next refueling outage, currently scheduled for the fall of 1995.
In the_ safety assessment included as part of the response, NPPD concluded that the operation of CNS until the next refueling outage would pose no undue risk from-the potential for core shroud cracking. _ In support of that conclusion, NPPD maintained that the core shroud has a relatively low susceptibility to cracking for the following reasons: (1) maintenance of good water chemistry at CNS, (2) applied loads to the core shroud during design basis events are low,-(3) the plant-specific minimum ligament required to maintain structural margins is 7 percent of wall thickness, and-(4) design margins would be maintained even with significant shroud cracking such that safety system effectiveness and _ core coolable geometry are ensured.
Further, the licensee's probabilistic safety assessment concluded that the estimated overall incremental core damage frequency is less than IE-6 per year, assuming a 360-degree circumferential, through-wall crack for a variety of l postulated accidents. The staff has reviewed the licensee's submittal and has. concluded that CNS core shroud is not likely to contain cracks which could compromise its structural integrity and that continued t
.
.- ' COOPER PRE-DECISIONAL o)eration is acceptable until detailed inspections can be conducted at tie next refueling outage.
MPA B-111: Generic LittignB8-20. Indiividual Pltnt Examination The licensee submitted the IPE for CNS, which consists of a Level 1 PRA and a level 2 PRA, on March 31, 1993. The estimated mean core damage frequency is 7.97E-5 per year. On October 21, 1994, the staff issued an extensive request for additional information (RAI) and the licensee's response to the RAI is currently under review by RES.
The staff's review is scheduled to be completed by June 1995.
MPA B-110: Generic letter 89-10. Motor-Operated Valves The licensee performed several GL 89-10 program activities, including the static testing of 30 MOVs, modifications to two reactor recirculation discharge MOVs, and some limited dynamic testing in January 1995. As a result, the staff approved the licensee's request for a schedule extension to defer coinpletion of the program until after the fall 1995 refueling outage. An NRC inspection of those activities also found a significant improvement in the overall GL 89-10 program over the poor quality observed in a 1993 inspection.
V.
STATUS OF THE PHYSICAL PLAAT A.
Problems Attributed to Acina None B.
Other Hardware Issues p(bV i M See attached risk impact study on hardware issues.
It@0T6 VI.
PRA A.
PRA Insichts t CNS is a BWR-4 with a Mark I containment. BWR PRAs indicate that station blackout is a major contributor to core damage frequency.
Offsite power for CNS is supplied from several 161-kV and 345-kV lines that feed into the start-up transformer, and a 69-kV line that feeds into an emergency transformer. The 69-kV power source supplies emergency loads only and had a poor record of spurious failures due to lightning strikes. After a safety system features inspection (SSFI) revealed voltage problems on the 69-kV line, a new substation was added to help control the power.
Since December 1992, the-69kV power source has been reliable. The site has never experienced a complete loss of offsite power.
The emergency diesel generators (EDGs) require control air to maintain a set engine speed and provide protective trip functions.
If control air is lost, the EDGs will shut down.
Instrument air' , tube cracking from vibration has resulted,in diesel engine trips.
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. .,-
- 4
, COOPER PRE-DECISIONAL l Relocating engine mounted instruments has rectified the situation because there have been no d.Asel engine trips in the last 2 years due to instrument air tube cracking.
In the event of a station blackout, the 250-Vdc and 125-Vdc batteries have the capacity to accommodate the-loads for a duration of 8 hours without load shedding. At CNS, both the air system' compressors and receivers are classified as essential, Published PRAs provide a strong indication that service water systems (!US) are risk significant.
In the past, CNS has experienced microbiological 1y induced corrosion (MIC) in certain sections of piping associated with the SWS (radiation monitor sample line) as a result of stagnant or low flow conditions. The licensee reviewed the SWS to identify sections of piping subject to these same conditions.
All identified sections of piping were inspected and no similar conditions were found. At CNS, the SWS was not originally designed as an ASME Code Class 3 system.
Although the SWS is included in the IST program, it has not been included in the ISI program in accordance with the provisions of 10 CFR 50.55a(g).
Therefore, the staff has suggested to RES that the treatment of the SWS failure rates should be evaluated carefully during the IPE review process.
The licensee plans to include the SWS in the ISI program at the 1995 refueling outage.
Also, in 1994, excessive silting was noted in the SWS as well as at the end of the SWS intake structure.
The licensee took actions to address silting concerns, including dredging the river bottom near the intake structure, and designing weir wall modifications to reduce silt buildup.
B.
PRA Profile ' in response to Generic Letter 88-20, the licensee submitted an IPE for CNS on March 31, 1993. The IPE was performed by a team of licensee staff and a contractor, SAIC.
In the IPE submittal, which contains a Level 1 and 2 PRA, the estimated mean core damage frequency is 7.97E-5 per year.
The IPE review is expected to be completed in June 1995. The IPE submittal does not provide a summary of th. risk profile in terms of initiating events and sequence contributions to core damage frequency, it does provide a risk profile in terms of accident type, which is presented below.
Accident Tvoe % of Core Damaae Frecuency Station Blackout 34.8 Transient Induced LOCAs 30.3 Loss of Coolant Injection 18.1 Loss of Containment Heat Removal 10.9 ATWS 4.9 LOCAs 0.9 Fast Containment Failures 0.1 Because the IPE was summarized in terms of accident type, a cursory review of the IPE by the staff was performed to try to
_---- ___ _ _ _ - _ _ _ _ _ _ _ .. . ' '* COOPER PRE-DECISIONAL categorize the risk profile in terms of initiators and sequence contributors to core. damage frequency for comparison purposes. On the basist_of this review, it appears that the Loss of Containment Heat Remo al category refers to sequences initiated by loss of servite ter. The Loss of Coolant injection category appears to k, s includenequences involving any type of transient with no injection systems of the required pressure evailable.
The most dominant contributors to accident sequences that lead to core damage were failure of the EDGs to continue to run, mechanical failures of the HPCI and RCIC systems and RCIC turbine, common cause failure (CCF) of all four SW pumps to run, CCF of the EDGs, failure of the operators to use the SRVs, and CCF of the SRVs.
' The IPEEE is scheduled for submission in December 1995.
C.
Core Damaae Precursor Events On the basis of the precursors identified by Oak Ridge National Laboratory (ORNL) for 1993 (NUREG/CR-4674, vols. 19 and-20) and the preliminary precursors for 1994, the staff did not identify any precursor events for the unit that have a conditional core damage probability of IE-5 per year or greater.
The following event has been classified as a "Potentially Significant Event Considered Impractical to Analyze" in the 1993 , NVREG/CR-4674, and as a "Significant Event" for the Performance Indicator Program.
From May 1992 until March 1993, CNS continued to operate with RCS leakage of approximately 0.4 gpm through both isolation valves of the shutdown cooling suction line. -This rate was sufficient to require the operators to establish a relief path from the suction line to the ECCS keep-fill system.
During the March 1993 refueling outage, the licensee disassembled and inspected both valves (for the first time) and found cracks in the seats and discs. The staff reviewed this event for implications with respect to interfacing system LOCA.It is not possible-to calcolate a conditional core damage probability for this event because there is no means available to determine the probability of failure for the suction isolation valves during the period of inte'.est at CNS, given the degree of leakage observed r.nd cracks frond.
If CNS had experienced gross failure of the RHR suction line isolation valves, the event would have been highly risk significant. Therefore, the physical condition of the plant may or may not have created a significant level of risk.
However, the actions of the licensee indicated a lack of appreciation for the risk associated with an interfacing systems LOCA.
The following event was classified as a "Significant Event" for the Performance Indicator Program. On May 25, 1994, both EDGs were declared inoperable when load shedding of all non-safety-related loads from the vital buses could not be verified.
The load shedding could not be verified because preconditioning for
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COOPER PRE-DECISIONAL past surveillance tests removed certain non-safety-related loads from the vital buses before the-EDGs were tested.
Thus, under worst case loading conditions, the EDGs may have been inoperable.
The worst case loading conditions are expected to exist during a LOOP /LOCA, which has a very low frequency of occurrence.
Subsequent testing demonstrated that not all non-safety-related loads would have shed. Calculations by the licensee showed that a niargin existed for the EDGs to be operable if those loads had remained tied to the buses. Although the staff could not independently confirm the licensee's calculations, the diesel manufacturer verified that the diesel could be operated for brief periods without damage at loads substantially above the maximum design rating. On this basis, the staff concluded that the diesel generators would probably have performed their intended function even if nonessential loads had not been automatically shed from the emergency buses.
The following was classified as an " Interesting" event in the 1993 NUREG/CR-4674. On February 25, 1993, a design basis review of the SWS and the reactor equipment cooling (REC) system identified that Division I SWS supplied the Division II REC heat exchanger and Division II SWS supplied the Division I REC heat exchanger. Given the design errors found, had CNS experienced a LOOP along with a failure of EDG-1, nonessential SWS and REC loads could not have 'been isolated-by remote means and the MOV supplying critical loop "A" REC loads would not have, opened.
Consequently, for the conditions assumed, adequate rooling to the operable EDG, the functional REC heat exchanger, the RHR SWS booster pump, and other loads could not have been assured.
Similar concerns exist for the failure of the Division II EDG.
EXPANDED PRA INSIGHTS Conclusions on the Cooper Nuclear Station Overall Risk Impact of the Hardware Issues Reoorted in 1994-The events analyzed include safety system failures (SSFs) in the Performance Indicator Program as well as start-up issues.
For the 11 events-analyzed, hardware failed or_ had the potential 8,o fail.
In addition to the events, the MOV issues were reviewed. *he l ~ event description, safety significance, and risk impact are addressed in_the following pages. The conclusions are stated below.
HARDWARE ISSUES Distribution of Hardware Issues Hardware issues were distributed among the following systems: System No. of Issues Emergency Diesel Generators (EDG)
High Pressure Coolant Injection (HPCI)
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i Reactor Core Isolation Cooling (RCIC)
Core Spray (CS)
Low Pressure Coolant injection (LPCI)
Service Water System (SWS)
Reactor Equipment Cooling (REC)
Standby Liquid Control (SLC)
Thus, the hardware issues are not related to a particular system.
Stanificant Events On May 25, 1994, both EDGs were declared inoperable because load shedding of all normal loads prior to starting the diesels during surveillance had not been achieved.
This was classified as a Significant Event.
Safety System Failures The number of SSFs in 1994 are above the BWR industry average.
The distribution of SSFs in 1994 are as follows: S / stem No. of SSFs Control Room Ventilation
Control Room Emergency Filtration
Standby Gas Treatment / Control Room
Emergency Filtration Emergency Diesel Generators
High Pressure Coolant Injection
Method of discoverv . About 50 percent of the hardware issues were found through surveillance testing or by review of surveillance test requirements.
This method of discovery for the HPCI problems is consistent with the results published in NUREG/CR, " Aging Study of Boiling Water Reactor High Pressure Injection Systems (DRAFT)," which deten...ined that the majority of HPCI failures were found through testing and inspection at BWRs.
The EDG issue was identified by the NRC.
The other issues were identified by the licensee through design reviews and walkdowns.
System Testina System testing in the past appeared to be inadequate.
Past surveillance testing practices did not adequately demonstrate EDG and CS system reliability under certain accident conditions.
Also, as part of the design basis reconstitution of the primary containment, the licensee discovered during walkdowns that several containment penetrations had never been tested by local leak rate testing (LLRT) or as a boundary during the integrated leak rate
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testing (ILRT).
In addition, certain REC piping had never been included in the ASME Section XI inservice inspection program and had been found leaking.
NOV Proaram The CNS HOV program is considered an acceptable GL 89-10 program, but is considered the weakest in Region IV.
The majority of MOV issues are programmatic and procedural. The discovery of potential overthrust conditions created in 1986 by modifications to 10 valve actuators is an example of a recent problem correction, rather than a problem creation.
HOV problems in the events were of a control and timing nature.
The "A" LPCI train outboard injection valve, though, experienced ' some leakage due to a foreign material exclusion problem.
RISK INSIGHTS Station blackout (SB0) is a major contributor to the CNS core damage frequency (CDF).
The EDG operability issue due to past surveillance testing preconditioning practices and the RCIC turbine trip throttle valve dependency on a.c. power would be expected to slightly increase the SB0 contribution to the CDF.
The IPE indicates that common cause failure of all four SWS pumps has a high risk achievement worth.
The observed silting in the river near the end of the intake structure would have been a common cause failure for the SWS pumps at minimum river levels.
The IPE indh.ates that the HPCI system failure to start and failure to continue to run are key contributors to the CDF.
The sensitivity studies indicated that the HPCI system CDF contribution could be reduced if certain system modifications were implemented; however, the implementation of those modifications would not have prevented the potential HPCI system inoperability due to the HPCI system hardware issues observed in 1994.
Saf.ety System Failures Durina Start-up in Februarv. 1995 CNS experienced three separate failures during start-up: 1.
Failure of 3 ADS valves to open on a manual signal 2.
Failure of an RHR suction valve to close on demand 3.
Failure of a vacuum breaker to remain closed SPSB reviewed these three failures and determined that they did not cause significant risk of core damage or release of radioactive material.
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.. . i.
COOPER PRE-DECISIONAL ' . VII. ENFORCEMENT HISTORY 10/93 - CIVIL PENALTIES (Supplement I, Reactor Operations; EA 93-137) The action was based on three Severity Level III problems associated with: (1) several violations of 10 CFR Part 50 that collectively indicated a breakdown in the licensee's corrective action program; (2) the failure to maintain the contain:::ent hydrogen / oxygen analyzers in an operable condition; and (3) the failure to include the service water and reactor equipment cooling systems in the inservice inspection program since initial plant operations.
Civil penalties were issued to emphasize the significance that the NRC attaches to these violations and the importance that the NRC attaches to NPPD's efforts to resolve deeply rooted and fundamental weaknesses in employee attitudes toward identifying and resolving problems. A civil penalty of $75,000 associated with the corrective action program was escalated for NRC identification. A civil penalty of $75,000 associated with the inoperable hydrogen / oxygen analyzers was escalated for NRC identification and multiple licensee opportunities to identify the problem but mitigated for the licensee's corrective actions. A civil penalty of $50,000 associated with the failure to include the service water and reactor equipment cooling systems in the inservice inspection program was not adjusted. ($200,000) 3/94 - ENFORCEMENT CONFERENCE (EA 94-005) . Two Severity Level IV violations were issued for inadequate procedures and weaknesses in the licensee's corrective action program.
4/94 - ENFORCEMENT CONFERENCE (EA 94-018) Several Severity Level IV violations were issued concerning the failure to follow-plant procedures; the failure to provide required quarterly training for the fire brigade; and the failure to maintain configuration control, 11/94, 2/95 - DEMAND FOR INFORMATION, SEVERITY LEVEL III VIOLATION AND ENFORCEMENT DISCRETION (Supplement I, Reactor Operations; EA 94-177, EA 95-012 The staff issued a demand for _information (DFI) related to a March 1993 violation of TS requirements governing the establishment of secondary containment before moving loads that could potentially damage irradiated fuel through the apparent careles disregard by Station Operations Review Committee (SORC) members in addressing a proposed change to procedures that resulted in the TS violation.
From a review of the response to the DFI, it was concluded that the SORC members were not unduly influenced by senior management and the SORC, at least collectively, considered the relevant requirements and safety considerations in arriving at the decision to revise-the subject procedures.
A Severity Level III problem was issued for violation of the TS and for the generation of inaccurate and incomplete information in the formulation of the procedure chanDe notices proposed to change the procedures that resulted in the TS violation.
The staff exercised broad discretion to refrain from proposing a civil penalty in this case to recognize the substantial changes and corrective actions implemented by the licensee in the two years since these violations occurred.
12/94 - CIVIL PENALTY (Supplement I, Reactor Operations; EA 94-164, 94-165, 94-166)
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_ , ' . . , F ' COOPER PRE-DECISIONAL Three Severity Level III actions were b6 sed on eight violations that were subsequently grouped into three problems. The first problem consisted of violations related to the primary containment system and failure to maintain operability, adequately test, and maintain design control of the system.
The second problem involved violations associated with the 480-volt and 4160-volt critical buses and failures to adequately test and maintain system operauility. The third problem consisted of violations pertaining to the - control room emergency filter system and failures to maintain operability and adequately test the system. Although application of the civil penalty adjustment factors could have resulted in a significantly higher civil penalty, discretion was used to set the total civil penalty at $300,000 or $100,000 for each of the three Severity Level III problems because of the licensee's initiative to shut down until successful implementation of an improvement program to address underlying root-causes of performance deficiencies, the licensee's commitment not to restart the plant without NRC approval, and the significant changes in the licensee's management oversight of site activities. ($300,000) .
e
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! ....J.- , . I , PRE-DECISIONAL . COOPER I.
HISTORY The Cooper Nuclear Station (CNS) was first discussed at the June 1993 SMM. The basis for concern was an apparent declining level of performance, in the previous two SALP periods, which ended in January 1992 and April 1993, performance declined in the areas of operations, radiological controls, maintenance / surveillance, engineering / technical support, emergency planning, and safety assessment / quality verification. Marginal performance, particularly in the areas of self-assessment and the implementation of corrective actions for identified problems, was apparent.
In January and June 1994 and January 1995, the NRC sent the licensee a trending letter requesting that appropriate remedial actions be taken.
The plant entered a forced, unplanned outage on May 25, 1994. The plant shutdown was initiated because the emergency diesel generators were declared inoperable due to concerns regarding their capability to supply emergency electrical loads in post-accident conditions. Concurrent with the development of this issue and after the plant had been shutdown, the inspection program identified that the control room emergency filtration system had been inoperable since 1989.
In addition, the licensee discovered, during design basis reconstitution efforts, that the containment had been inoperable since 1974.
The root causes for the inoperability of these engineered safety feature systems included: an approach to testing to obtain the desired results instead of obtaining the as-found data, inadequate testing procedures; a lack of a questioning attitude regarding test performance and results; and a lack of management oversight of the testing program. The NRC subsequently issued escalated enforcement and a Civil Penalty for these violations.
On February 9, 1995, after extensive management and program changes, the plant resumed power operation.
At the June 1994 SMM, NRC managers recognized the need to obtain additional insight into the performance of CN3 management and staff.
Accordingly, AE00 established, based on Diagnostic Evaluation Team principles, a Special Evaluation Team (SET), which assessed the licensee's performance in October 1994.
The licensee also recognized a need for a Diagnostic Self Assessment Team (DSAT) inspection. In June 1994, the licensee selected an independent group to perform a third party evaluation of CNS.
Inspection findings, in a report issued in September 1994, identified significant weaknesses in management, overall performance, and program implementation. The SET inspection efforts validated the results of the DSAT.
II.
CHANGES SINCE LAST SMM Since July 1994, the licensee has replaced 9 of the 10 key managers below the Vice President-Nuclear.
The new management team successfully implemented the first phase of a three-phase performance improvement program (PIP) to prepare the plant for restart.
The NRC approved the PIP in February 1995.
The NRC CNS Restart Panel, established in accordance with Inspection Manual Chapter 0350, concluded that the licensee had adequately addressed the management weaknesses --
- _ _ _ _ _ - _ _ _ - - _ _ - _ _ _ _ _ _ , COOPER PRE-DECISIONAL -' i that were identified as the root causes of the observed problems in programs and performance by the NRC SET and the independent DSA7.
The panel reviewed extensive inspection data collected over several months, including the findings of the NRC restart team inspection conducted in January 1995. The restart team found that the area of operations was a relative strength and that corrective actions and management involvement and oversight were improved.
Improvements were also noted in the control of testing activities and in the surveillance testing and inervice testing programs.
Engineering was noted as an area of relative weakness. Direct observation of licensee performance by Region IV and NRR during startup and power ascension activities confirmed all of these conclusions.
In addition, the quality assurance organization appeared to take a more active role in monitoring plant activitizs and the Station Operations Review Committee was considered to be more effective in questioning issues brought for review.
The new managenent team's philosophy regarding the development of a safety culture that promotes a questioning attitude appears to be filtering down to working level personnel. The site manager and the plant manager are clearly the catalysts for change, and they also recognize the need for continued emphasis in this area.
The interim restart organization functioned effectively, with better work control and communication between departments. However, significant resources were expended during the restart effort in the use of overtime and contractor support, which the licensee plans to minimize now that the unit is back on line. Further observation of the licensee's implementation of Phases 2 and 3 of their performance improvement plan is necessary to assess whether the pace of recent improvements can be sustained.
I The licensee encountered some difficulties during initial attempts at startup, which commenced on February 9,1995, including the failure of three safety / relief valves (SRVs), the failure of two SRV tailpipe vacuum breakers, and the discovery of potential problems with the operation of several MOVs due to vibration-induced movement of the valve stem protective caps.
The licensee took appropriate corrective action to resolve these problems and power ascension and subsequent operation at 100 percent power have proceeded smoothly since February 19. The physical plant has presented relatively few challenges for the licensee since the resolution of the initial problems described above.
On February 14, Mr. Ron Watkins, President and CEO of the Nebraska Public Power District (NPPD), announced his resignation effective April 1,1995. Mr. Watkins accepted the position of President and CEO of Old Dominion Electric Cooperative (0DEC) in Glen Allen, Virginia. In a newspaper interview, he indicated that his reason for leaving was the attractive financial package offered by ODEC, and not for reasons related to Cooper's extended shutdown or regulatory issues.
Mr.
Robert L. Gangel, currently Vice-President for Finance and Administration, assumed the president's responsibilities until a permanent successor is named.
On February 13, 1995, NPPD announced the reorganization of the Nuclear Power Group Engineering Department and the relocation of major engineering functions from the General Office in Columbus to the Cooper site.
On May 1, 1995, Mr.
Philip D. Graham assumed the new position of Senior Manager of Engineering, responsible for all NPPD engineering activities at Cooper.
All current g engineering employees were required to apply for positions in the new organization, which is scheduled to take effect on June 1, 1995.
As of May 8,
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- - _ - __- __ ______ - __ __ _ _ . _ _ . _. _ . . COOPER PRE-DECISIONAL 3 of 4 managers and 8 of 17 first-line supervisors had been selected; final selection of internal staff for the new positions was in progress.
Additional outside recruitment may be necessary to fill some supervisory vacancies and several staff positions, due to the departure of a number of current engineers who were unwilling to relocate.
The licensee is evaluating options for short-term engineering support through contractors or sharing of resources with other utilities. When fully staffed, approximately 110 engineering positions will be located onsite; a small transitional engineering group will remain in Columbus through the end of the year.
NPPD believes the reorganization will result in ' more effective engineering support at Cooper and in significant cost savings for the utility.
III.
FUTURE ACTIVITY The licensee's new management team has acknowledged the need for comprehensive improvement of the CNS custom technical specifications (TS). The licensee has selected a consultant to perform a scoping study of the options for TS improvement, including conversion to the Improved Standard TS.
Based on the results of this scoping study, the licensee expects to develop a specific plan for TS upgrade by late summer 1995, with a comprehensive upgrade package to be submitted in the fall 1996. The licensee has also held preliminary discussions with the licensees of a number of other boiling water reactor (BWR) Mark I plants to explore the potential for joint efforts toward TS improvement.
In the interim, the NRR staff and the licensee have mutually agreed that several individual TS should be promptly revised, including TS for diesel generator operability, control room envelope surveillance te: ting, and logic system functional testing (LSFT).
The NRR staff and the licensee will continue to assess the need for additional license amendments to clarify or correct the existing TS on an individual basis, pending the licensee's final decision and implementation of a comprehensive TS improvement program.
The licensee is also conducting an extensive review of its surveillance test program, which will help to ensure that surveillances properly confirm equipment and system operability beyond TS requirements.
Administrative procedures have been adopted for certain equipment surveillances to specify allowed outage times that are not explicitly addressed in the current TS.
These procedures pr vide a documented process for dealing with the lack of detail in some TS, in contrast to the previous practice of implementing TS requirements based on informal and inconsistent interpretations.
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. . COOPER-PRE-DECISIONAL
DATA SUMMARY I.- 0FERATIONAL PERFORMANCE A.
Scram Sumary None B.
Sionificant Operator Errors None C.
Procedures-Significantdeficiencieshavebeenidentifiedwithstation-surveillance procedures.
Several deficiencies have been identified where surveillance procedures were not sufficient to demonstrate technical specification operability.
II.
CONTROL ROOM STAFFING A.
Number of Licensed Goerttors 18.Q ' EQ LSE.Q lQI_% I
14
44 .B.
Number and tenoth~of Shifts Six, 12-hour shifts C.
Role of STA- ' s The STAS. at CNS are on duty for a 24-hour rotational period. They-are not_ assigned to an operating crew; however, they do receive training with a specific shift crew.
STAS do not hold a senior-reactor' operators license.
The STA's primary duty is to act as an , accident prevention and mitigation advisor to the shift supervisor.
The licensee is currently training STAS for normal ~ shift rotation, which began in January _1995.
D.
Raggalification Proaram Evaluation ' A requalification program evaluation conducted in_ December 1993 , resulted in a satisfactory rating for the program.
The inspectors ', used guidance provided in NUREG-1021," Operator Licensing Examiner Standards," Revision 7, Sections 601_through 605. The licensed operator performance had improveo since the= last program evalua-tion. The improvement in command and control and communications was noted.
Region IV will conduct an inspection in accordance g with IP-71001, " Licensed Operator Requalification Program Evalua-tion," during the month of November 1995.
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l ' ! COOPER PRE-DECISIONAL III.
PLANT-SPECIFIC INFORMATION A.
Plant-Snecific Information Plant Cooper Nuclear Station (CNS) Owner Nebraska Public Power District (NPPD) Reactor Supplier / Type GE/BWR Capacity, MWe 778 AE/ Constructor Burns & Roe ' CP Issued: 6/4/68 OL 1ssued: 1/18/74 Commercial Operation Date 7/1/74 B.
Unioue Desian Information Containment: Mark I, with a hardened vent Emeraency Core Coolina Systems: Two loops of low pressure core spray, two loops of low pressure coolant injection, one high pressure coolant injection system, one reactor core isolation-cooling system, and an automatic depressurization system.
AC Power: Five 345-kV lines, one 161-kV line and one 69-kV line; two turbocharged, V-16, Cooper-Bessemer diesel generators.
DC Power: Four Class IE batteries with 8-hour capacity (and four battery chargers), two 125-volt and two 250-volt.
IV.
SIGNIFICANT MPAs OR PLANT-UNIQUE ISSUES MPA B-125 Generic Letter 94-03, "IGSCC of Core Shrouds in BWRs": In its August 26, 1994, response to the subject GL, NPPD indicated that it will perform inspections of the CNS core shroud at the next refueling outage,-currently scheduled for the fall of 1995.
In the safety assessment included as part of the response, NPPD concluded that the operation of CNS until the next refueling outage would pose no undue risk from the potential for core shroud cracking.
In support of that conclusion, NPPD maintained that the core shroud has a relatively low susceptibility to cracking for the following reasons: (1) maintenance of-good water chemistry at CNS, (2). applied loads to the core shroud during design basis events are low, (3) the plant-specific minimum ligament required to maintain structural margins is 7 percent of wall thickness, and (4) design margins would be maintained even with significant shroud cracking such that safety system effectiveness and core coolable geometry are ensured.
Further, the licensee's probabilistic safety assessment concluded that the estimated overall incremental core damage frequency is less than IE-6 per year, assuming a 360-degree circumferential, through-wall crack for a variety of postulated accidents.
The staff has reviewed the_ licensee's submittal and has concluded that CNS core shroud is not likely to contain cracks which could compromise its structural integrity and that continued
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_. _ _ _ _ _ _ _ _. _ _. _ _ _. . COOPER PRE-DECISIONAL ' o)eration is acceptable until detailed inspections can be conducted at tie next refueling outage.
MPA B-111 Generic Letter 88-20 " Individual Plant Examination": The licensee submitted the IPE for CNS, which consists of a Level I pRA and a Level 2 PRA, on March 31, 1993.
The estimated mean coro damage frequency is 7.97E-5 per year. On October 21, 1994, the staff issued an extensive request for additional information (RA!) and tne licensee's response to the RAI is currently under review by RES.
The staff's review is scheduled to be completed by June 1995.
MPA B-110 Generic Letter 89-10. " Motor-0perated Valves":.The licensee perfonned several GL 89-10 program activities, including the static testing of 30 MOVs, modifications to two reactor recirculation discharge MOVs, and some limited dynamic testing in January 1995.
As a result, the staff approved the licensee's request fer a schedule extension to defer completion of the program until after the fall 1995 refueling outage. An NRC inspection of those activities also found a significant improvement in the overall GL 89-10 program over the poor quality observed in a 1993 inspection.
, V.
STATUS OF THE PHYSICAL-PLANT , A.
Problems Attributed to Acina None i B.
Other Hardware Issues See attached risk impact study on hardware issues.
VI.
PRA A.
PRA. !nsight.1 CHS is a BWR-4 with a Mark I containment.
BWR PRAs indicate that station blackout is a major contributor to core damage frequency.
Offsite power for CNS is supplied from several 161-kV and 345-kV lines that feed into the start-up transformer, and a 69-kV line that feeds into an emergency transformer. The 69-kV power source supplies emergency loads only and had a poor record of spurious failures due to lightning strikes. After a safety system features inspection (SSFI) revealed voltage problems on the 69-kV line, a-new substation was added to help control the power.
Since December 1992, the 69kV power source has been reliable. The site has never experienced a complete loss of offsite power.
The emergency diesel generators (EDGs) require control air to maintain a set engine speed and provide protective trip functions.
If control air is lost, the EOGs will shut down.
Instrument air tube cracking from vibration has resulted in diesel engine trips.
g Relocating engine mounted instruments has rectified the situation because there have been no diesel engine trips in the last 2 years
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In the. event of a station
blackout, the 250-Vdc and 125-Vdc batteries have the capacity to accommodate the loads for a duration of 8 hours without load ' shedding. At CNS, both the air system compressors and receivers
are classified as essential.
! Published PRAs provide a strong indication that service water systems (SWS) are risk significant.
In the past, CNS has
experienced microbiological 1y induced corrosion (MIC) in certain j sections of piping associated with the SWS (radiation monitor sample line) as a result of stagnant or low flow conditions.
The ' licensee reviewed the SWS to identify sections of piping subject to these same conditions.
All identified sections of piping were inspected and no similar conditions were found. At CNS, the SWS was not originally designed as an ASME Code Class 3 system.
Although the SWS is included in the IST program, it has not been . included in the ISI program in accordance with the provisions of 10 CFR 50.55a(g).
Therefore, the staff has suggested to RES that the treatment of the SWS failure rates should be evaluated ! carefully during the IPE review process.
The licensee plans to include the SWS in the ISI program at the 1995 refueling outage.
Also, in 1994, excessive silting was noted in the SWS as well as at the end of the SWS intake structure.
The licensee took actions to address silting concerns, including dredging the river bottom ' near the intake structure, and designing weir wall modifications , to reduce silt buildup.
. 8.
PRA Profile l In response to Generic letter 88-20, the licensee submitted an IPE for CNS on March 31, 1993.
The IPE was performed by a team of , licensee staff and a contractor, SAIC.
in the IPE submittal, which contains a Level 1 and 2 PRA, the estimated mean core damage frequency is 7.97E-5 per year. The IPE review is expected to be completed in June 1995.
The IPE submittal does not provide a summary of the risk profile in terms of initieting events and sequence conti.butions to core damage frequency.
It does provide a risk profile in terms of accident type, which is presented below.
Accident Tvoe % of Core Damaae Freauency Station Blackout 34.8 Transient Induced LOCAs 30.3
Loss of Coolant injection 18.1
Loss of Containment Heat Ren'aval 10.9 ATWS 4.9
LOCAs 0.9 Fast-Containment Failures 0.1 i Because the IPE was susarized in terms of accident type, a - cursory review of the IPE by the staff was performed to try to categorize the risk profile in terms of initiators and sequence contributors to core damage frequency for comparison purposes. On
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I . COOPER PRE-DECISIONAL the basis of this review, it appears that the Loss of Containment Heat Removal category refers to sequences initiated by loss of service water. The loss of Cooiant Injection category appears to include sequences involving any type of transient with no injection systems of the required pressure available.
The most dominant contributors to accident sequences th:t lead to cora damage were failure of the EDGs to continue to run, mechanical failures of the HPCI and RCIC systems and RCIC turbine, common cause failure (CCF) of all four SW pumps to run, CCF of the EDGs, failure of the operators to use the SRVs, and CCF of the SRVs.
The IPEEE is scheduled for submission in December 1995.
C.
Core Damace Precursor Events On the basis of the precursors identified by Oak Ridge National Laboratory (OR?ll) for 1993 (NUREG/CR-4674, vols. 19 and 20) and the preliminary precursors for 1994, the staff did not identify any precursor events for the unit that have a conditional core damage probability of IE-5 per year or greater.
The following event has been classified as a "Potentially Significant Event Considered impractical to Analyze" in the 1993 NUREG/CR-4674, and as a "Significant Event" for the Performance i Indicator Program.
From May 1992 until March 1993, CNS continutd to operate with RCS leakage of approximately 0.4 gpm through both isolation valves of the shutdown cooling suction line.
This rate was sufficient to require the operators to establish a relief path from the suction line to the ECCS keep-fill system.
During the March 1993 refueling outage, the licensee disassembled and inspected both valves (for the first time) and found cracks in the seats and discs. The staff reviewed this event for its implications with respect to interfacing system LOCA.
It is not possible to calculate a conditional core damage probability for this event because there is no means available to determine the probability of failure for the suction isolation valves during the period of interest at CNS, given the degree of leakage observed and cracks found.
If CHS had ex)erienced gross failure of the RHR suction line isolation valves, tie event would have been highly risk significant. Therefore, the physical condition of the plant may or may not have created a significant level of risk.
However, the actions of the licensee indicated a lack of appreciation for the risk associated with an interfacing systems LOCA.
The following event was classified as a "Significant Event" for the Performance Indicator Program.
On May 25, 1994, both EDGs were declared inoperable when load shedding of all non-safety-related loads from the vital buses could not be verified.
The load shedding could not be verified because preconditioning for g past surveillance tests removed certain non-safety-related loads from the vital buses before the EDGs were tested.
Thus, under l
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._ . - COOPER PRE-DECISIONAL worst case loading conditions, the EDGs may have been inoperable.
The worst case loading conditions are expected to exist during a LOOP /LOCA, which has a very low frequency of occurrence.
Subsequent testing demonstrated that not all non-safety-related loads would have shed.
Calculations by the licensee showed that a margin existed for the EDGs to be operable if those loads had remained tied to the buses.
Although the staff could not independently confirm the licensee's calculations, the diesel manufacturer verified that the diesel could be operated for brief periods without-damage at loads substantially above the maximum design rating. On this basis, the staff concluded that the diesel generators would probably have performed their intended function even if nonessential loads had not been automatically shed from the emergency buses.
The following was classified as an " Interesting" event in the 1993 NVREG/CR-4674. On February 25, 1993, a design basis review of the SWS and the reactor equipment cooling (REC) system identified that Division 1 SWS supplied the Division 11 REC heat exchanger and Division II SWS supplied the Division I REC heat exchanger. Given the design errors found, had CNS experienced a LOOP along with a , failure of EDG-1, nonessential SWS and REC loads could not have been isolated by remote means and the MOV supplying critical loop "A" REC loads would not have opened.
Consequently, for the conditions assumed, adequate cooling to the operable EDG, the functional REC heat exchanger, the RHR SWS booster pump, and other loads could not have been assured.
Similar concerns exist for the failure of the Division 11 EDG.
EXPANDED PRA INSIGHTS Conclusions on the Coooer Nuclear Station Overall Risk Imoact of the Hardware issues Reported in 1994 The events analyzed include safety system failures (SSFs) in the Performaace Indicator Program as well as start-up issues.
Fcr the 11 events analyzed, hardware failed or had the potential to fail.
- In addition to the events, the MOV issues were reviewed. The event description, safety significance, and risk impact are addressed in the following pages. The conclusions are stated below.- HARDWARE ISSUES Distribution of Hardware Iss.un Hardware issues were distributed among the following systems: System No. of Issues Emergency Diesel Generators (EDG)
High Pressure Coolant injection (HPCI)
Reactor Core Isolation Cooling (RCIC)
Core Spray (CS)
9 i
. COOPER PRE-DECISIONAL Low Pressure Coolant Injection (LPCI)
Service Water System (SWS)
Reactor Equipment Cooling (REC)
Standby Liquid Control (SLC)
Thus, the hardware issues are not related to a particular system.
Sionificant Events On May 25, 1994, both EDGs were declared inoperable because load - shedding of all normal loads prior to starting the diesels during surveillance had not been achieved.
This was classified as a Significant Event.
' Safety System Failures The number of SSFs in 1994 are above the BWR industry average.
The distribution of SSFs in 1994 are as follows: System No. of SSFs Control Room Ventilation
Control Room Emergency Filtration
Standby Gas Treatment / Control Room
Emergency Filtration Emergency Diesel Generators
High Pressure Coolant injection
l , Method of discovery About 50 percent of the hardware issues were found through surveillance testing or by review of surveillance test requirements.
This method of discovery for the HPCI problems is consistent with 'the results published in NUREG/CR, " Aging Study of Boiling Water Reactor High Pressure injection Systems (DRAFT)," which determined that the majori+y of HPCI failures were found through testing and inspection at bwRs.
The EDG issue was identified by the NRC. The other issues were identified by the licensee through design reviews and walkdowns.
-System Testina System testing in the past appeared to be inadequate.
Past surveillance testing practices did not adequately demonstrate EDG and CS system reliability under certain accident conditions.
Also, as part of the design basis reconstitution of the primary containment, the licensee discovered during walkdowns that several containment penetrations had never been tested by local leak rate testing (LLRT) or as a boundary during the integrated leak rate g testing (ILRT).
In addition, certsin REC piping had never been '
. . _ ... . . - . . _.-
COOPER PRE-DECISIONAL ' included in the ASME Section XI inservice inspection program and had been found leaking.
MOV Proaram The CHS MOV program is considered an acceptable GL 89-10 program, but is considered the weakest in Region IV.
The majority of MOV issues are programmatic and procedural.
The discovery of potential overthrust conditions created in 1986 by modifications to 10 valve actuators is an example of a recent problem correction, rather than a problem creation.
MOV problems in the events were of a control and timing nature.
The "A" LPCI train outboard injection valve, though, experienced some leakage due to a foreign material exclusion problem.
RISK INSIGHTS Station blackout (SBO) is a major contributor to the CNS core damage frequency (CDF). The EDG operability issue due to past surveillance testing preconditioning practices and the RCIC turbine trip throttle valve dependency on a.c. power would be expected to slightly increase the 580 contribution to the CDF.
The IPE indicates that common cause failure of all four SWS pumps has a high risk achievement warth. The observed silting in the river near the end of the intake structure would have been a common cause failure for the SWS pumps at minimum river levels.
The IPE indicates that the HPCI system failure to start and failure to continue to run are key contributors to the CDF.
The sensitivity studies indicated that the HPCI system CDF contribution could be reduced if certain system nodifications were implemented; however, the implementation of those modifications would not have prevented the potential HPCI system inoperability due to the HPCI system hardware issues observed in 1994.
Safety System Failures Durina Start-up in February. 1995 CNS experienced three separate failures during start-up: 1.
Failure of 3 ADS valves to open on a manual signal 2.
Failure of an RHR suction valve to close on demand 3.
Failure of a vacuum breaker to remain closed SPSB reviewed these three failures and determined that they did not cause.significant risk of core damage or release of radioactive material.
Il _ _ _
. - _ _ _ .. _ . ... - COOPER PRE-DECISIONAL VII.
ENFORCEMENT HISTORY 10/93 - CIVIL PENALTIES (Supplement 1. Reactor Operations; EA 93-137) The action was based on three Severity Level 111 problems associated with: (1) . several violations of 10 CFR Part 50 that collectively indicated a breakdown in the licensee's corrective action program; (2) the failure to maintain the containment hydrogen / oxygen analyzers in an operable condition; and (3) the failure to include the service water and reactor equipment cooling systems in the inservice inspection program since initial plant operations.
Civil penalties were issued to emphasize the significance that the NRC attaches to these violations and the importance that the NRC attaches to NPPD's efforts to resolve deeply rooted and fundamental weaknesses in employee attitudes toward identifying and resolving problems. A civil penalty of $75,000 associated with the corrective action program was escalated for NRC identification.
A civil penalty of 575,000 associated with the inoperable hydrogen / oxygen analyzers was escalated for NRC identification and multiple licensee opportunities to identify the problem but mitigated for the licensee's corrective actions. A civil penalty of $50,000 associated with the failure to include the service water and reactor equipment cooling systems in the inservice inspection program was not adjusted. (5200,000) 3/94 - ENFORCEMENT CONFERENCE (EA 94-005) Two Severity Level IV violations were issued for inadequate procedures and weaknesses in the licensee's corrective action program.
) 4/94 - ENFORCEMENT CONFERENCE (EA 94-018) Several Severity Level IV violations were issued concerning the failure to follow plant 3rocedures; the failure to provide required quarterly training for the fire arigade; and the failure to maintain configuration control.
11/94, 2/95 - DEMAND TOR INFORMATION, SEVERITY LEVEL 111 VIOLATION AND ENFORCEMENT DISCRETION (Supplement I, Reactor Operations; EA 94-177. EA 95-012 The staff issued a demand for information (DFI) related to a March 1993 violation of TS requirements governing the establishment of secondary containment before moving loads that could potentially damage irradiated fuel through the apparent careless disregard by Station Operations Review Committee (SORC) members in addressing a proposed change to procedures that resulted in the TS violation.
From a review of the response to the DFI, it was concluded that the SORC members were not unduly influenced by senior management and the SORC, at least collectively, considered the relevant requirements and safety considerations in arriving at the decision to revise the subject procedures.
A Severity Level III problem was issued for violation of the TS and for the generation of inaccurate and incomplete information in the formulation of the l procedure change notices proposed to change the procedures that resulted in the TS violation.
The staff exercised broad discretion to refrain from proposing a civil penalty in this case to recognize the substantial changes ' and corrective actions implemented by the licensee in the two years since these violations occurred.
(
l ,- _
. i . COOPER PRE-DECISIONAL 12/94 - civil PENALTY (Supplement _1, Reactor Operations; EA 94-164,94-165,94-166) Three Severity Level !!! actions were based on eight violations that were subsequently grouped into three problems.
The first problem consisted of violations related to the primary containment system and failure to maintain operabilityleminvolvedviolationsassociatedwiththe480-voltand4160-volt adequately test, and maintain design control of the system. The second prob critical buses and failures to adequately test and maintain system operability.
The third problem consisted of violations pertaining to the control room emergency filter system and failures to maintain operability and adequately test the system. Although application of the civil penalty adjustment factors could have resulted in a significantly higher civil penalty, discretion was used to set the total civil penalty at $300,000 or $100,000 for each of the three Severity Level 111 problems because of the licensee's initiative to shut down until successful implementation of an improvement program to address underlying root causes of performance deficiencies, the licensee's commitment not to restart the plant without NRC approval, and the significant changes in the licensee's management oversight of site activities. ($300,000)
, ! ' COOPER
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,' <, , ' l COOPER Licensee: Nebraska Public Power District (NPPD) Reactor Type: BWR/4 (GE) Power Level: 778 MWe Date of Construction Permit: 06/04/68 Date of Operating License: 01/18/74 Operating License Expiration: 01/18/2014 Construction Period Recapture Date: N/A CURRENT OPERATING UJAIMS On February 6, 1995, the Regional Administrator (RA) granted NRC - approval for plant restart.
Cooper restarted on February 9, 1995, following a 209-day forced outage.
The plant was shut down from 5% power on February 10, 1995, due to the failure of 3 safety / relief valves to open during surveillance testing. The licensee was also investigating problems with a motor-operated RHR pump suction valve.
The licensee expects to resolve those issues and resume restart activities by February 14, 1995.
The forced outare resultet from significant problems with the electrical - distribution system, the control room emergency filtration system, containment integrity and surveillance testing; for which the licensee received a $300K civil penalty in December.
Other problems included weaknesses in the review of industry operating experience and the performance of the Station Operations Review Committee.
These issues were the subjects of two Confirmatory Action Letters and a third letter from the RA to the licensee.
The NRC Special Evaluation Team (completed in October) and the licensee's Diagnostic Self-Assessment (completed in August) independently concluded that management weaknesses were the root cause of the identified problems.
CURRENT ISSUES Since July 1994, the licensee has replaced 8 of the 10 key managers - below the Vice President-Nuclear.
In recommending restart, an NRC Cooper Restart Panel reviewed extensive - inspection data collected over several months, including the findings of an NRC restart team inspection.
The restart team concluded that the area of operations waa a relative strength and that corrective actions, management involvement and oversight were improved.
Engineering was noted as an area of relative weakness. The licenseo plans to reorganize the engineering function, including relocation of engineering resources to the site to provide Letter plant support.
RECENT LICENSEE PERFORMANCE The most recent SALP report is almost two years old (spring 1993).
Due - to the extended forced outage, the current SALP period will not end until July 8, 1995.
In the last SALP, the areas of maintenance / surveillance and safety assessment / quality verification declined to - - - [
_ ' e . ,
2-category 3 ratings; the other areas remained category 2 ratings (except security, which again was rated category 1).
Cooper has been a full discussion plant at the last three NRC Senior - Management Meetings (SMM), and has received a trending letter following each SMM. The most recent letter, dated February 1, 1995, acknowledged that the licensee's corrective actions have been responsive to the areas of concern raised by the NRC and the licensee's own self-assessments, but that the NRC needed additional time to assess the effectiveness of these corrective actions.
Twenty-four hour NRC staff site coverage will be implemented for - approximately 4 weeks, throughout startup and power ascension.
CONTACT: James R. Hall 415-1336 February 13, 1995 _ =. =_ _. - -. _. - - - - -
. . ..
BACKGROUlm INFORMATION ! fB COOPER NUCLEAR STATION Utility: Nebraska Public Power District (NPPD) location: 23 miles south of Nebraska City, Nebraska County: Nemaha County, Nebraska Docket No.: 50-298 CP !ssued: June 4, 1968 OL !ssued: January 18, 1974 Initial Criticality: February 21. 1974 Commercial Operation: July 1, 1974 Reactor Type: BWR Containment Type: MARK I Power Level: 778 MWe; 2381 MWt Architect / Engineer: Burns & Roe NSSS Vendor: General Electric Constructor: Burns & Roe Turbine Supplier: Westinghouse Condenser Cooling Method: Once Thru Condenser Cooling Water: Missouri River . Licensing Project Manager: Randy Hall, NRR (301/504-1336) NRC Responsible Reglen: Region IV, Arlington, Texas L. J. Callan, Regional Administrator John M. Montgomery, Deputy Regional Administrator Div. of Reactor Projects A. Bill Beach, Director (817/860-8183) (Region IV) Jim Dyer, Deputy Director (817/860-8248) Phil Harrell, Chief, Project Branch C (817/860-8250) Terry Reis, Project Engineer (817/860-8185) Senior Resident inspectors: Ron Kopriva (402/825-3371) Mary Miller (402/825-3371) eff. 4/95 Resident Inspector: Wayne Walker (402/825-3371) Report Coordinated By: Terry Reis (817/860-8185) NPPD Manaaement Personnel, See enclosed licensee organization charts.
The licensee has made a number of management level personnel changes in July - September, 1994. The changes involve the hiring of personnel from outside NPPD and include: Site Manager: John Mueller Plant Manager: John Herron Plant Operations Manager:. Paul DiRito-1-03/10/95 /UAl
. ': . Scheduling Manager: Terry Foster Plant Engineering Manager: James Gausman QA Manager: Andy Sessoms Senior Manager of Safety Assessment: Ray Jones Events Analysis Manager: Chuck Gaines Licensing Manager: Robert Godley Emergency Preparedness Manager: Brad Houston Workforce Staffing level at the plant: approximately 450 (does not include contract security staff) Reactor Ooerators Total Licensed Operators:
Total Number of SR0s:
Total Number of R0s:
There are an additional 9 SR0s with inactive licenses.
DIk1MI.11 The licensee has six shifts of five licensed operators each.
The licensee has two Senior Reactor Operators (SR0s) (one shift supervisor and one control room supervisor), three Reactor Operators (R0s)he requirement for shift staffing and three nonlicensed operators on each shift crew.
This shift force meets t during reactor operation.
The licensee is progressing toward having an STA assigned to each operating crew. Currently, an STA is assigned and on call 24 hours / day.
A support crew is onsite 4 days a week during the day shift, with an additional crew onsite for training.
Reactor Ooerator Exams Administered by the Reaton Date of Number of Exam Aeolicants Passed Failed May 1992 1 SR0 1 SRO O 2 R0 2 R0
May 1993 6 R0 6 R0
The next initial examinations are scheduled for May 1995. The requalification inspection is scheduled for November 1995.
Plant Simula1.gr A plant-specific simulator began training operations on June 4,1990. The certified simulator is located in the Cooper Nuclear Stetion training facility, which is situated outside the licensee's protected area.
Systematic Assessment of Licensee Performance (SALP) A SALP review was conducted for the period of January 19, 1992, through April 24, 1993.
The Final SALP report was issued (NRC Inspection Report 50-298/92-99) on August 27, 1993.
The current SALP period has been-2-03/10/95
. . Coocer Nuclear Statiof} extended untti July 8,1995, in order to ensure an adequate assessment of Cooper Nuclear Station in an operating mode can be made.
l Itatina last Period Ratina This Period (07/16/90 - 01/18/92) (01/19/92 - 04/24/93) Plant Operations
2 Radiological Controls
21 Maintenance / Surveillance
3 Emergency Preparedness
20 Security
1 Engineering / Technical
2 Support Safety Assessment /
3 Quality Verification TT)-ImprovingTrend (D) - Declining Trend Escalated Enforcement Actions An enforcement conference was conducted on January 31, 1994, which addressed concerns associated with the loss of both emergency diesel generators.
Two Severity Level IV violations were identified involving failure to follow procedures, procedures that were inappropriate to the circumstances, and inadequate corrective actions.
No civil penalty was proposed.
An enforcement conference was conducted on April 4, 1994, to discuss issues raised during the 0)erational Safety Team inspection conducted in November 1993.
Eigit Severity Level IV violations were identified with no civil penalty.
An enforcement conference was conducted on September 16, 1994, to discuss the issues involving the apparent inoperability of both emergency diesel generators, primary containment, and the control room envelope.
Three Severity Level 111 violations were identified and a $300,000 civil penalty was imposed on December 12, 1994.
The civil penalty was paid without contest on January 18, 1995.
An escalated enforcement action resulted from the closure of an investigation concerning a procedure change that permitted movement of heavy loads over the core without maintaining secondary containtoent integrity in April 1993.
The February 8 action issued a Severity level 111 problem, but no civil penalty was imposed in accordance with the terms of the enforcement policy.
-3-03/10/95 i
t . Cooper Nuclear Station Investiaation/A11eaation Status An investigation concerning a procedure change that permitted movement of heavy loads around the core without maintaining secondary containment integrity was completed. As a result of this investigation and other NRC inspections, significant concerns were identified with the performance of the Station Operations Review Committee (SORC).
The concerns involved the SORC's ability to effectively implement its oversight functions.
This issue was satisfactorily resolved through the licensee's Phase 1 - Performance improvement Plan and the NRC's Restart Action Plan. The 01 investigation concluded that SORC members did act with careless disregard and thus caused regulatory requirements to be violated. After examining the responses to the Demands for Information issued relative to this case, the staff does not support a finding of careless disregard.
These differing perspectives need to be formally reconciled.
Emeraency Preparednesi The licensee has maintained the emergency response facilities in a state of operational readiness.
No exercise weaknesses were identified during the annual exercise conducted in December 1993. An exercise was conducted in November 1994 and two weaknesses were identified.
One involved the transmission of erroneous and conflicting information to offsite response ) agencies concerning the status of radioactive releases and the second was identified for a weak exercise scenario.
Overall, licensee management adequately demonstrated its ability to protect the public health and safety in a simulated emergency.
Operating crews evaluated ir the control room simulator performed well in detecting and classifying simulated emergency conditions.
Previously, this was an area of weakness.
Sianificant Licensee Accomolishments The lic.ensee instituted a new management team in the third quarter of 1994 which developed and implemented a successful plan to correct programmatic deficiencies that led to an extended shutdown that began May 25, 1994.
NRC authorization of plant restart was granted on February 6,1995, and full power operations were resumed on February 27, 1995.
Plant Status Plant Ooerations Cooper Nuclear Station completed its refueling outage on July 29, 1993.
The unit operated at approximately 100 percent power until May 1994, when an unplanned plant shutdown occurred.
-4-03/10/95 l
. .. _ - _ -
. - - _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _, . . C.gprer Nuclear station Recent Planned and/or Unolanned Nonrefuelina Outaa n r On May 25, 1994, the facility was shut down because the_ licensee declared both emergency diesel generators (EDGs) inoperable and JJm~a~ ins _ s_hud' programmatic ' tdown-pending the licensee's resolution of a number of significant technical an issues.
The licensec declared the EDGs inoperable because a test to verify the load shedding function of electrical loads from the vital electrical busses had not been adequately performed.
This issue was identified as a result of a tie wrap being found on the undervoltage trip device in a nonsafety-related breaker.
The installation of the tie wrap would have prevented the breaker from load shedding from the bus during an undervoltage condition.
in addition to the electrical bus load shedding problems, concerns were identified with the capability of the control room envelope and primary containment to meet their intended design functions.
As a result of the significance of these issues, Confirmatory Action Letters, dated July 1 and August 2, 1994, were issued to require the licensee to address these three issues prior to restart of the facility. During review of these three issues, additional related concerns with the licensee's performance were identified. Accordingly, the NRC's Manual Chapter 0350, " Staff Guidelines for Restart Approval," was implemented.
The additional concerns involve the review of operating experience information, apparent preconditioning of systems and components prior to testing, adequacy of the surveillance testing arogram, and maintaining system and component design basis information.
Tie licensee developed formal corrective actions to address the deficiencies and the staff developed an action plan in accordance with Manual Chapter 0350 to pusess the adequacy of the corrective actions and their implementation. The licensee successfully developed and implemented appropriate actions, and restart authorization was granted on February 6, 1995.
Refuelina Outaae The plant began Refueling Outage 15 on March 5, 1993, and completed the outage on August 1 (149-days).
The outage had been scheduled for 56-days; howevar, emergent work activities, particularly in the area of motor-operated valve testing, resulted in the extended outage.
Other major work activities completed included inspection / repair of the torus and installation of the wetwell hardened vent.
The next refueling outage is scheduled for fall 1995.
Other Recent Plant Issues As a result of previous concerns with the licensee's performance, two trending letters have been issued to notify the licensee of the NRC's assessment of a negative trend in overall perfonnance.
in response to these letters, the licensee initiated a diagnostic self-assessment effort to evaluate performance and to identify areas where enhanced management oversight was required.
The assessment was performed by experienced personnel from industry, INPO, and-5-03/10/95
_ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _, - .
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Cooper Nuclear station private fims, f)the individuals had previous involvement with the Cooper Nuclear Station.
The diagnostic self-assessment report was issued on September 2, 1994.
NRC management decided, in light of the issuance of two trending letters, to perform a diagnostic evaluation at Cooper Nuclear Station.
The evaluation effort (Special Evaluation Team (SET)) was reduced from that of a typical Disgnostic Evaluation Team because the licensee opted, in conjunction with agreement from the NRC, to )erform a self-assessment.
The SET completed its activities in October and tle report was issued November 30, 1994.
The concerns identified by the Diagnostic Self-Assessment Team and SET were addressed by both the licensee and the NRC as part of the Manual Chapter 0350, " Staff Guidelines for Restart Approval," process, which was terminated on February 28, 1995.
Sianificant Desian Information
ECCS: Two loops of low pressure core spray: two loops of low pressure coolant injection, one high pressure coolant injection, one reactor core isolation cooling system, and an automatic depressurization system Containment:
General Electric Mark 1, pressure suppression
On-site emergency AC power: Two EDGs Station Batteries:
Two -125-volt, Two 250-volt
Station Blackout: No major modifications required Status of Physical Plan 1 No major plant aging issues have been identified. The licensee is scheduled to inspect the core shroud for cracks during the next refueling outage (fall 1995).
AEOD Analysis of Ooerational Data The AE00 data for the six-quarter period ending 94-4 is difficult to interpret due to the extended shutdown. The operations data is not meaningful.
The shutdown data shows Cooper Nuclear Station has deviated significantly from the peer group safety system failures and design problems.
The safety system failures include the control room ventilation deficiency, the reactor core isolation cooling system's failure to comply with station blackout, and the improper setting of the high pressure coolant injection system low steamline isolation pressure switches.
-6-03/10/95 _
- - - _. _ _ _ ' . .'
. (ooner Nuclear Station NRR Ooeratina Reactor Assessment Since July 1994, the licensee has replaced 8 of the 10 key managers below the Vice President-Nuclear.
The new management team successfully implemented the first phase of a three-phase performance improvement program (PIP), in preparing the plant for restart, which the NRC approved in February 1995.
The NRC Cooper Restart Panel concluded that the licensee had effectively addressed - the management weaknesses that were identified as the root causes of the observed problems in programs and performance by the NRC SET and the third party Diagnostic Self-Assessment Team. The Panel reviewed extensive inspection data collected over several months, including the findings of the NRC restart team inspection conducted in January 1995. The restart team f)und that the area of operations was a relative strength and that corrective actions, management involvement, and oversight were improved.
Improvements were also noted in the control of testing activities and in the surveillance testing and inservice testing programs.
Engineering was noted as an area of relative weakness.
Direct observation of licensee performance by Region IV and NRR staff during startup and power ascension activities confirmed these findings.
In addition, Quality Assurance appeared to take a more active role in monitoring plant activities.
The Station Operations Review Committee was considered to be more effective in questioning issues brought for their review.
The new management team's philosophy regarding the development of a safety culture that promotes a questioning attitude appears to be filtering down to working level personnel.
The Site Manager and the Plant Manager are clearly the catalysts for change; they also recognize the need for continued emphasis in this area. The interim restart organization functioned effectively, with better work control and communications between departments.
However, significant resources were expended in the restart effort through the use of overtime and contractor support, which the licensee plans to minimize now that the unit-is back on line.
Further observation of the licensee's implementation of Phases 2 and 3 of their PIP is necessary to assess whether the recent improvements can be sustained.
The licensee encountered some difficulties during the initial attempts at startup, which commenced on r bruary 9, 1995, including the failure of three e safety / relief valves,-the failure of two safety / relief valves' tailpipe vacuum breakers, and the discovery of potential problems with the operation of several motor-operated valves due to vibration-induced movement of the valve stem protective covers along the valve stems. The licensee took appro)riate corrective action to resolve these problems and power ascension and su) sequent operation at 100 percent power have proceeded smoothly from the February 19 startup. The physical plant has presented relatively few challenges for the licensee-since the resolution of the initial problems.
On Febrnry 14, Mr. Ron Watkins, President and CEO of the Nebraska Public Power District (NPPD), announced his resignation, effective April 1, 1995.
Mr. Watkins has accepted the position of President and CEO of Old Dominion Electric Cooperative in Glen Allen, Virginia.
In a newspaper interview, he indicated that his reason for leaving was the attractive financial package offered by ODEC and not for reasons related to Cooper's extended shutdown or-7-03/10/95 H , . .. ... - . _. o
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Mr. Robert L. Gangel, currently Vice-President for finance t and Administration, will be acting in those positions until a permanen regulatory issues.
successor is named.
Power NPPD announced the reorganization of the Nuclear functions Group Engineering Department and the relocation of major engineer On February 13, 1995, from the General Office in Columbus to the Cooper site.
the reorganization by October 1995, approximately 90 to 110 engine i oup will positions will be located onsite; a small transitional engineer ng grThe remain in Columbus for the next year. reorganization will result in more in sdgnificant cost savings for the utility.
been well received by the engineering staff; it is not cicar how many engineers may leave the company.
i has The adequacy of the Cooper Nuclear Station t.usto ' d In discussions between the staff and for licensee, several individual Technical Specifications have been ta for comprehensive improvements.
for diesel revision in the near term, including the Technical Specificationsco The licensee is conducting an extensiveimpact of generator operability,ing.
system functional testsurveillance test program upgrade effort, in any Technical Specification inadequacies.
procedures to specify allowed outage times for equipment surve These procedures are not addressed in the current Technical Saecifications.f instru provide a documented process for dealing wit 1 the lack oTechnical Specifications, rather than the pas s open to informal and inconsistent interpretations.
for Technical selecting a contractor to perform a scoping study of the options d Specification improvement, including conversion to the Impro toward Technical Specifications.with a number of other BWR h d led to meet on May C, 1995, to explore the concept further.
Public Issues l Public involvement in the Manual Chapter 0350 process was lim media coverage and co-owners of the facility.
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