IR 05000298/1998003
| ML20249C079 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 06/23/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20249C075 | List: |
| References | |
| 50-298-98-03, 50-298-98-3, NUDOCS 9806250287 | |
| Download: ML20249C079 (20) | |
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ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
l Docket No.:
50-298
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License No.:
DPR-46 Report No.:
50-298/98-03-Licensee:
Nebraska Public Power District Facility:
Cooper Nuclear Station Location:
P.O. Box 98 Brownville, Nebraska Dates:
April 19 through May 30,1998 inspectors:
Mary Miller, Senior Resident inspector Chris Skinner, Resident inspector Approved By:
Elmo Collins, Chief, Branch C Division of Reactor Projects ATTACHMENT:
Supplemental Information 9906250287 990623 P
PDR ADOCK-OS000298 e
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EXECUTIVE SUMMARY Cooper Nuclear Station NRC Inspection Report 50-298/98-03
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Operations Plant management continued to demonstrate intrusive involvement in plant activities
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resulting in examples of improved safety performance. Examples included identification and correction of weak setpoint change implementation and correction of inadequate service water system flow balancing. Strong expectations for improved performance continued. Plant staff addressed some specific issues in a more timely and thorough manner (Section 01.1).
The operations control room staff performance continued to be generally good, with
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many examples of outstanding communications and command and control. However, in a few cases under a high routine work load, control room communications and command and control were much less formal. Management demonstrated strong involvement and crew management demonstrated a safety focused, proactive response to off-normal plant and offsite conditions. Shift supervisor standards and demands for plant support of control room issues were generally excellent. However, shift supentisors frequently did not provide strong leadership while running the plan of the day meeting (Section 01.2).
The operability evaluations performed during this inspection period were generally good,
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with some exceptions. This represented an improvement over past inspection periods (Section 02.2).
Maintenance Maintenance activities observed by inspectors were conducted effectively
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(Section M1.1).
In general, plant material condition was good. Inspectors noted continuing improvement
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in the appearance of plant equipment. Inspectors observed some examples of degraded plant equipment and operator work-arounds (Section M2.1).
The licensee identified that a surveillance procedure intended for outages only was
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inappropriately scheduled for power operation. The procedure was not implemented, but no restrictions had been documented in the procedure. The evaluation did not consider that the original 10 CFR 50.59 evaluation may have been inadequate. Also, the licensee did not recognize that service water backup cooling could be prevented by a single failure (Section M3.1).
Over the past few months, maintenance has improved somewhat. Most of these
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improvements have been specific corrective actions implemented by the licensee's
- corrective action program. Some improvement resulted from involvement of management and supervision with maintenance technicians to articulate and maintain higher standards for maintenance work and program implementation (Section M7.1).
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' An indication light failed on the high pressure coolant injection steam admission valve.
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Subsequent troubleshooting did not identify the cause of failure. The subsequent engineering evalu'ation was weak. Applicable industry information was not addressed, the potential effect on valve control switches was not addressed, and operability was -
concluded without identifying the source of the foreign material which was concluded to
- have caused the problem. Significant inspector involvement was required before relevant aspects of operability were addressed (Section E2.1).
Although battery room temperatures have been maintained within operability.
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requirements, the licensee enters an abnormal low battery room temperature procedure every summer since the essential ventilation keeps temperatures low enough to '
potentially challenge the battery operability. Proceduies which required operators to set up temporary heaters when required contained minor weaknesses. Engineering has not yet provided a permanent resolution for the work-around (Section E2.2).
Plant Support
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The licensee did not provide an explanation conceming why an inoperable radiation monitor was not fixed in a timely manner, in the Annual Radioactive Materials Report, as required by Technical Specifications 3.21.A.1.d. This situation was caused by operation of the service water system with RHR heat exchanger outlet valves leaking. Also, the licensee did not recognize the reporting requirements with liquid discharges occurring with the radiation monitors inoperable (Section R2.1).
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R,oort Details i
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Summarv of Plant Status The plant was at 100 percent power at the beginning of this report period. A downpower to 68 percent was performed on May 16,1998, for scheduled turbine valve testing. The plant returned to full power on May 18,1998.
l 1. Operations
Conduct of Operations 01.1 Plant Manaaement involvement in Plant Activities a.
Insoection Scoce (71707)
Inspectors attended shift turnover meetings, reviewed shift tumover briefing sheets, and attended and reviewed minutes of routine meetings, including condition review group, plan-of-the-day, and station operations review committee.
b.
Observations and Findings inspectors observed that plant management intervened during routine and special purpose plant meetings to obtain more comprehensive and complete staff response to operational occurrences, in-process problems, and technical evaluations.
For example, during each of approximately 20 plan-of-the-day meetings observed, the inspectors noted that the plant manager or acting plant manager intervened during discussions of plant issues to specify that additional aspects of problems ared evaluations had not been satisfactorily addressed and that better performance by the plant staff was
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expected. This involvement also occurred in other meetings observed. Plant j
department heads usually immediately became engaged and proposed actions to address the concerns. Followup to understand how the issue was being addressed was j
typically performed on or before the following day's meeting.
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The concerns raised by the plant manager or the acting plant manager demonstrated a
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need for the plant or engineering staff to more thoroughly understand or bound a j
condition, more broadly question potential root causes of problems, and communicate in a more effective and timely manner between departments in correcting or resolving a problem.
One of the more significant findings identified was the recognition that the implementation of the improved Technical Specifications had not undertaken a thorough review of operational procedures to determine if the setpoint changes affected plant operating procedures. During the program presentation for the Safety Review and Audit Board meeting on May 21, the plant manager and another member identified that calibration and specific system operating procedures were not the only procedures j
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-2-affected and thei questioned the adequacy of the scope of the procedure reviews. The program owner, outside the plant managers organization, took no actions to bound the concern. In response, the plant manager ordered a stop to setpoint changes and assigned the shift crews to coordinate reviews of operating, abnormal, and emergency procedures to identify potential consequences of setpoint changes on those procedures.
That evening, a crew identified an abnormal procedure which was affected by the new feed pump trip setpoint and required a procedure setpoint change. Setpoint changes were implemented in the plant only after the procedure reviews were completed.
Other examples of management intervention included questioning whether goals existed for expected rates of maintenance work completion, adequacy of coordination with engineering to address service water system anomalies and proper flow balancing of the service water and turbine equipment cooling water, allocation and balance of resources to address the initiatives and inspections scheduled for the following 2 weeks, and recognition that coordination and contingency planning had not been done properly during an earlier extent of condition investigation.
During this inspection period, the response to sorne of the specific routine issues by the plant staff, and to some extent, by engineering, improved somewhat in timeliness and scope. This appeared to be a result of the continued involvement by plant management in setting standards and expectations for timely communications and issue identification and resolution.
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Conclusions Plant management continued to demonstrate intrusive involvement in plant activities, resulting in examples of improved safety performance. Examples included identification
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and correction of weak setpoint change implementation and correction of inadequate service water system flow balancing. Strong expectations for improved performance continued. Plant staff addressed some specific issues in a more timely and thorough
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O1.2 Control Room Staff Performance Durina Routine and Off-Normal Conditions a.
Insoection Scooe (71707)
l Inspectors observed multiple shift turnovers and routine evolser,s, such as surveillance testing and control rod manipulations. The inspectors observed control room staff response to a potential fire in a service water pump room and crew response to other off-normal conditions. Inspectors also observed the shift supervisors management of the plan-of-the-day meeting, b.
Observations and Findinas Shift turnovers were conducted in an organized and formal manner. Safety focus was evident in the. issues and priorities identified by the control room staff. Operators i
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3-effectively anticipated conditions requiring entry into emergency procedures, such as tornado watches and high river level. The crews also responded promptly to unanticipated emergency procedure entry conditions, such as a radiation monitor failure and a potential fire indication. The crews demonstrated excellent safety focus and command and control by suspension of ongoing activities in a thoughtful and controlled manner, appropriate plant announcements, and excellent procedure adherence. Routine operations were generally good, but communications and command and control became less formal when multiple routine evolutions were being performed. Under these circumstances, communications degraded to a lower level of formality. An example of these degraded communications was a situation involving simultaneous troubleshooting of rod positioning circuitry, initiation of a monthly surveillance run, and interaction with several technicians at the control room window.
On May 14, the control room responded to offsite power issues, which began with one offsite breaker having its automatic reclose function disabled. The inspector observed prompt, proactive response and involvement by the shift supervisor, shift technical engineer, operations manager, and scheduling manager. Engineering assistance was requested and provided within an hour. An assessment of the potential offsite distribution overload was promptly initiated, since thunderstorms were expected and lightning could affect an offsite breaker with a disabled automatic reclosure feature, and portions of the power distribution network may have been challenged by peak power use.
The licensee found that the parallel path of the offsite distribution system would not be overloaded by the loss of the breaker with disabled automatic reclosure function, even under expected peak power conditions. A risk assessment was also performed, indicating that no significant change in risk would be expected with the loss of one of the six offsite power sources. These conclusions were reached within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after the control room was notified that the automatic reclosure function was disabled.
On May 20, inspectors observed the control room response to an acrid odor in the service water pump room. Since no assessment of the conditions in the room could be obtained without potential threat to personnel, the control room activated the fire brigade response team, entered the fire procedure, and immediately terminated all activities not
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associated with the fire response. Control room demeanor and operator activities were outstanding. Radio communications with the fire brigade members was challenged and at times became somewhat informal, particularly during use of self-contained breathing apparatus. Upon entry into the area by the fire brigade, they determined that the smell
was generated by maintenance use of muriatic acid.
in general, inspectors found that the control room evidenced generally good control room demeanor, communications, command and control, and contingency planning in both l
l routine and emergency / abnormal operations. However during routine operations when several independent activities were ongoing, control room demeanor degraded to a level of adequate, with weaknesses observed in communications and positive control. The
licensee acknowledged that this area should be addressed.
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-4 Inspectors observed that shift supervisors were generally outstanding as demanding customers of plant support to the control room. However, although shift supervisors ran
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the daily plan-of-the-day meeting, they did not provide strong leadership or expectations during their leadership of the plan-of-the-day meetings. Examples where they did not
- provide strong expectations during this meeting included maintenance schedule adherence, satisfactory completion of activities by engineering, and resolution of administrative and plant support issues.
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Conclusions The operations control room staff performance continued to be generally good, with l
many examples of outstanding communications and command and control. However, in a few cases under a high routine work load, control room communications and command and control were much less formal. Management demonstrated strong involvement and crew management demonstrated a safety focused, proactive response to off-normal plant and offsite conditions. Shift supervisor standards and demands for plant support of control room issues were generally excellent. However, shift supervisors frequently did not provide strong leadership while running the plan of the day meeting.
Operational Status of Facilities and Equipment O2.1 Technical Specification Containment Sorav Permissive Setooint a.
insoection Scoce (71707)
Inspectors reviewed an operability assessment regarding the setpoint for the containment spray permissive logic. Inspectors held discussions with operators, engineers, and licensing staff.
b.
Observations and Findinas The licensee identified that the setpoint for Drywell Pressure Containment Spray Permissive Pressure Switches PC-PS-119A, -B, -C, and -D, as stated in Technical Specification Table 3.2.b as less than or equal to 2 psig, was incorrect with respect to the original design. The original design requirements for this setpoint was greater than 2 psig. The instruments were calibrated consistent with Technical Specification limits.
The licensee addressed this error with Problem Identification Report 2-21362. An operability evaluation concluded that the switch was operable and would perform its design basis function.
The original Technical Specification for the crywell pressure permissive for containment spray was inaccurate. The licensee identified this concern during a review of the Updated Safety Analysis Report.
_ One of the design functions of the switch setpoint is to ensure termination of containment i-spray at the scram seipoint. Another function is to ensure that the containment will not
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h-5-become subatmospheric, require actuation of the reactor building to torus vacuum breakers, and de-inert the primary containment. Although the use of containment spray during design basis accident mitigation is described in the Updated Safety Analysis Report, containment spray is not required to successfully mitigate a design basis event.
A March 1972 letter from General Electric to the licensee stated that the function of these pressure switches was proposed as prevention of activation of containment spray below a given containment pressure to provide assurance that the subatmosphere design limits for primary containment would not be exceeded following operation of containment spray. The original instrument setpoint was specified to be at the scram setpoint (2 psig). The operabit!ty evaluation stated that Calculation NEDC 89-1904, which identified acceptable regions for initiation of the containment spray mode, demonstrated that, with the drywell pressure scram set at 2 psig, the restriction directed to crews, on
~ initiation of containment spray (Graph 9 of Attachment 1 of Emergency Operating Procedure 5.8), ensured that the pressure in the drywell would not drop below the containment pressure scram setpoint if containment spray was initiated. This indicated
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that the licensee relied on the operator's manual action implemented in an emergency operating procedure to ensure a containment design requirement listed in Technical Specifications was met. Generic Letter 91-18 indicated that automatic actions (an automatic shutoff of the containment spray function upon reset) required by Technical Specifications should not have manual actions as a basis for operability. Licensing stated that the use of containment spray was beyond design basis events and, therefore, manual action could be relied upon to fulfil the spray shutoff function.
. Inspector review found that, with potential instrument inaccuracies and tolerances, the actuation and reset may be less than the General Electric specified limit of the reactor scram limit of 2 psig. The reset of the switch may be as low as 1.08 pounds. Regarding the inaccuracy of the Technical Specification limit, the licensee stated that they expected to correct the error during the improved Technical Specifications program, but the correction was not accomplished. The reliance on manual action for an automatic function required by Technical Specifications, and the potential that the original Technical Specifications were incorrectly implemented, will be an unresolved item (50-298/98003-01).
O2.2 Review of Operability Ev_alMali2DS a.
Insoection Scoce (71707)
I Inspectors reviewed several operability assessments. Inspectors held discussions with operators, engineers, and licensing staff.
b.
' Observations and Findinas Several operability evaluations were reviewed during this inspection period. They addressed the design requests of the structures, systems, or components in varying L
degrees of detail. Some required clarification of the basis for operability in a more
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-6-detailed manner, which was not considered a significant weakness. All provided a satisfactory basis for operability with the exception of the evaluations described in Sections O2.1, E2.1, and M2.1.
c.
Conclusion The operability evaluations performed during this inspection period were generally good, with specific exceptions noted in this report. This represents an improvement over past inspection periods.
Miscellaneous Operations issues 08.1 (Closed) Unresolved item 50-298/97005-04 (EA 98-346): 10 CFR 70.24 - Criticality monitoring program for fuel handling. This issue involved the failure to have in place either a criticality monitoring system for storage and handling of new (nonirradiated) fuel or an NRC approved exemption to this requirement contained in 10 CFR 70.24.
10 CFR 70.24 requires that each licensee authorized to possess more than a small amount of special nuclear material (SNM) maintain in each area in which such material is handled, used, or stored a criticality monitoring system which will energize clearly audible alarm signals if accidental criticality occurs. The purpose of 10 CFR 70.24 is to ensure that, if a criticality were to occur during the handling of SNM, personnel would be alerted to that fact and would take appropriate action.
Most nuclear power plant licensees were granted exemptions from 10 CFR 70.24 during the construction of their plants as part of the Part 70 license issued to permit the receipt of the initial core. Generally, these exemptions were not explicitly renewed when the
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Part 50 operatir,g license was issued, which contained the combined Part 50 and Part 70 authority. In August 1981, the Tennessee Valley Authority (WA), in the course of reviewing the operating licenses for its Browns Ferry facilities, noted that the exemption to 10 CFR 70.24 that had been granted during the construction phase had not been explicitly granted in the operating license. By letters dated August 11,1981, and August 31,1987, WA requested an exemption from 10 CFR 70.24. On May 11,1988, NRC informed TVA that "the previously issued exemptions are still in effect even though the specific provisions of the Part 70 licenses were not incorporated into the Part 50 license." Notwithstanding the correspondence with TVA, the NRC has determined that, in cases where a licensee received the exemption as part of the Part 70 license issued during the construction phase, both the Part 70 and Part 50 licenses should be examined to determine the status of the exemption. The NRC view now is that, unless a licensee's licensinn basis specifies otherwise, an exemption expires with the expiration of the Part 70 in,ense. The NRC intends to amend 10 CFR 70.24 to provide for administrative controls in lieu of criticality monitors.
The NRC has concluded that a violation of 10 CFR 70.24 existed. The NRC has also l
determined that numerous other licensees have similar circumstances that were caused j
L by confusion regarding the continuation of an exemption to 10 CFR 70.24 originally l
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-7-issued prior to issuance of the Part 50 license. After considering all the factors that resulted in these violations, the NRC has concluded that, while a violation did exist, it is appropriate to exercise enforcement discretion for violations involving special circumstances in accordance with Section Vil B.6 of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600.
The inspectors found that the licensee had submitted an exception to 10 CFR 70.24 on February 23,1998. On May 22,1998, NRR issued the exemption. This item is closed.
08.2 (Ocen) Unresolved item 50-298/98002-05: Failure of an emergency procedure to implement the design basis. Inspectors identified another example in that Procedure 5.2.5, " Loss of Offsite Power," did not address the need to operate cross-connect valves between the emergency diesel generator main fuel tanks about 3 days after initiation of an event. This action would allow the remaining tank to supply fuel to the operating diesel generator for the full 7 days required by Technical Specifications.
The licensee acknowledged this finding and corrected the procedure. The licensee pointed out that, if the valves were not manually operated, the redundant fuel pump would provide fuel from the second tank in response to the redundant level switches in the day tank. This indicated that, although engineering had not provided instructions for this need, the lack of specific instructions to cross-connect the tanks would not have prevented the second '.nk from being used to supply the running diesel.
II. Maintenance M1 Conduct ' Maintenance M1.1 General Comments a.
Insoection Scoce (62707 and 61726)
The following maintenance activities were observed:
Preventive Maintenance 04799 - Calibration, lubrication, and inspection of Suppression Chamber Water Temperature Recorder PC-TR-25 Maintenance Work Request 98-1290 - Inspection of limit switches for High Pressure Coolant injection Steam Supply Valve HPCI-MOV-M014
I Surveillance Procedure 6. ADS.303 - Automatic Depressurization System Logic System
. Functional Test
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Observations and Findings -
During the observation of the above maintenance activities, the inspectors observed L
procedure adherence, appropriate control of replacement parts, good work practice, and l
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-8-an appropriate threshold for identification of conditions adverse to quality. Supervisory oversight was occasionally observed in the field.
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Conclusions
- Maintenance activities observed by inspectors were conducted effectively.
M2 Maintenance and Material Condition of Facilities and Equipment '
M2.1 Material Condition Observations a.
Insoection Scone (71707)
Inspectors conducted plant walkdowns, reviewed problem reports, and discussed various issues with plant staff to assess plant material condition.
b.
Observations and Findinas 1.
In general, inspectors noted continuing improvement in the appearance of plant equipment. One exception was the diesel generators, which did not show significant improvement in the cleanup of oil leaks. Station operators have greatly improved and maintained the overall appearance.of equipment. Fluid leaks and grime have been removed. Overall visibility and impression of cleanliness in the plant equipment areas is significantly improved.
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Inspectors noted that, during summer months, operators routinely entered the abnormal procedure to address battery room temperatures which were low. This required logging temperatures and, if temperatures reached a value close to the battery operability limit, heaters were placed in service. This concem is being followed by the operator work-around log and is described further in Section E2.2.
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Valve HPCI MO 14 failed.to indicate closed when it was cycled for routine
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surveillance. Foreign material was assumed to have been the cause, although no method for introduction was identified. This issue is described in Section E2.1.
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standby status. This results in a discharge of service water. Manual actions are-required to sample the discharge for radioactive material and is further discussed L
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- In general, plant material condition was good. Inspectors noted continuing improvement in the appearance of plant equipment, inspectors observed some examples'of degraded plant equipment and operator work-arounds.
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M3
~ Maintenance Procedures and Documentation
LM3.1 IDADR[Qatih(REC) Surveillance
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- Insoection Scone (61726)
Inspectors evaluated licensee activities associated with their identification of a surveillance procedure weakness and subsequent root cause and safety significance -
evaluation. Inspectors reviewed procedures, problem identification reports, root cause evaluation,'and system drawings and operating procedures associated with the issue.
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Observations and Findings
' Three surveillance on the REC system did not properly identify what would render both REC subsystems inoperable. One procedure was recently scheduled but was not performed in the run mode.
On February 9,1998, work control identified that a scheduled surveillance should not be performed. Procedures 15. REC.301, "A REC Non-Critical Loop Low Pressure Isolation
' Calibration and Functional Test REC-PS-452A," Revision 1,15.1 REC.301, "A REC -
Non-Critical Loop Low Pressure isolation Calibration and Functional Test REC-PS-4528 (Div I)",' Revision 0, and 15.2 REC.301, "A REC Non-Critical Loop Low Pressure Isolation c
Calibration and Functional Test REC-PS452B2 (Div 2)," did not identify that they would
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make both REC subsystems inoperable during surveillance performance.- These procedures required opening of valves, which isolate essential from nonessential portions of the REC system. After the salves were opened, the breakers were opened to
ensure the valves did not change position. Problem identification Report 2-19942 identified that both subsystems of REC would be inoperable while this maintenance was in progress and the valves were failed to the open, nonsafety position. After the report.
was processed, operations management identified that this condition was potentially
. reportable s'ince the licensee may not have been aware that the REC system was -
inoperable while this maintenance occurred.
The licensee corrected the procedure, identified and corrected procedures with similar weaknesses, and re-emphasized a need for awareness'of the operability implications of procedures.
. inspectors found 'that the licensee root cause team had not questioned the adequacy of
the procedure's 10 CFR 50.59 evaluation. _ Inspectors found that the 10 CFR 50.59
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evaluation did not specify that the procedure would render the REC system inoperable.
The evaluation team was led by maintenance, and the members were unaware of the need for 10 CFR 50.59 evaluations to appropriately evaluate safety implications of the procedures: Therefore, the licensee had not addressed potential root causes in -
1 inadequate evaluations or the potential extent of condition of procedures with inadequate
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-10-The licensee's closure documentation of the problem identification report provided an evaluation of the safety significance of the inadequate procedure. The licensee identified that these procedures had been performed once in 1987 at power and also routinely during outages. The licensee found that the procedure steps had been performed within the time of the Technical Specification action statement requirements for the reactor equipment cooling system, although the action statement had not been entered. The licensee further concluded that the system had been operable since the service water backup had been available in the event of a loss of REC. The inspector questioned this conclusion and determined that, in a design basis event, with failure of the Division ll electrical system, service water flow would be diverted from the essential portion of the REC system.
The licensee responded by reopening the problem identification report. The licensee also indicated that the service water backup is not a design basis backup for the REC system. This issue will be tracked as an inspection followup item pending the licensee's final safety significance and deportability evaluations (298/98003-02).
c.
Conclusion The licensee identified that a surveillance procedure intended for outages only was inappropriately scheduled for power operation. The procedure was not implemented, but no restrictions had been documented in the procedure. The licensee's evaluation did not consider that the original 10 CFR 50.59 evaluation may have been inadequate. Also, the licensee did not recognize that service water backup cooling could be prevented by a single failure.
M7 Quality Assurance in Maintenance Activities M7.1 Maintenance Proaram improvements and Self-Assessments a.
Scone (617071 Inspectors reviewed maintenance problems and associated corrective actions Inspectors also observed maintenance technicians' work standards and management and supervisory interaction in both field and shop meetings and discussions. Inspectors reviewed Quality Assurance audits and self-assessment plans.
b.
Observations and Findinas Inspectors observed improvements in maintenance practices and programs. These j
improvements resulted from articulation of management expectations, involvement, and
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corrective action program actions. First, plant management articulated clear
expectations to more closely control work to schedules, document problems, more effectively track and drive down backlogs, and reduce challenges to the control room.
These expectations were implemented in meetings with maintenance and scheduling staff and were observed to have caused improvements in schedule completion,
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-11-reduction of backlogs, and reduction of control room challenges. Second, actions taken as a result of problems documented in the corrective action program have resulted in improvements in performance. deveral improvements in the programs and work standards of technicians have been implemented. Examples of these are a generally lower threshold for problem identification, stronger procedure adherence, identification and correction of several surveillance scheduling weaknesses, and correction of specific proceduralinterface inadequacies. Some resolutions of significant conditions adverse to qcality have been outstanding. Others have been adequate, with isolated examples of inadequate resolutions identified by both inspectors and plant management.
Another cause of improvements was quality assurance surveillance and audits. These audit areas have included corrective action, training, measurement and test equipment, observations of maintenance work, and observations of day-to-day interfaces of maintenance with scheduling, operations, and engineering. Inspectors observed that, frequently, actions in response to quality assurance findings have resulted in a higher standard of work by maintenance craft.
Inspectors reviewed maintenance self-assessment and improvement plans. The program has not been implemented to date. The plans as written were not integrated, but were later shown to be generally aligned with an overall maintenance organization strategy.
c.
Conclusion Over the past few months, maintenance has improved somewhat. Most of these improvements have been specific corrective actions implemented by the licensee's corrective action program. Some improvement resulted from involvement of management and supervision with maintenance technicians to articulate and maintain higher standards for maintenance work and program implementation.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) LER 95-005-00: Safety relief valves failed to operate during manual actuation surveillance testing. On February 10,1995, the automatic depressurization system failed surveillance testing. The actuators for the solenoid valves were found to have been rusted and corroded which restricted motion and therefore failed in place. The licensee determined that the root cause of the rust and corrosion was moisture left in the solenoid assemblies during a hydrostatic test of the valve body at the vendor facility. This hydrostatic test used a method which did not follow the normal hydrostatic test and subsequent drying process. The LER described the supplier as well as the test process and determined that replacement of the valve adequately corrected the problem. The LER stated that it si:.tisfied the 10 CFR Part 21 reporting requirement.
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E2-Engineering Support of Facilities and Equipment E2.1 Foreian Material Found on Limit Switch for Hiah Pressure Coolant injection Valve a.
.lnsoection Scoce (37551)
l Inspectors reviewed the licensee's operability evaluation and resolution of the failure of the Valve HPCI MOV-14 indication light. Inspectors observed maintenance, reviewed
i engineering evaluations and maintenance work orders, and held discussions with engineers, operators, and maintenance technicians.
b.
Observations and Findinos Valve HPCI MOV-14, the steam admission valve for the high pressure core injection
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pump turbine, failed its surveillance test because the closed light indication failed to light when the valve was closed Troubleshooting found that the limit switch had not properly made contact to extinguish the closed light. Engineering concluded that foreign material had lodged on the limit switch and caused the open circuit. The limit switch was cleaned
- and the valve tested satisfactorily. A formal root cause investigation was not initiated, since engineering considered this concern to be associated with indication only.
Inspectors noted that engineering had not addressed how the valve had passed prior postmaintenance tests before the failure, did not consult maintenance to determine how the foreign material may have entered the valve, and did not explore if procedures or I
work practices should be changed. The potential effects on the other (valve control) limit switches in the limit switch housing had not been assessed. Inspectors found that only the failed indication limit switch had been cleaned and that the valve control switches had not been inspected or cleaned.
inspectors also noted that the valve was not installed vertically as recommended by the vendor, but at an angle. Also, this valve leaks by, allowing steam to heat the valve continuously, inspectors asked why the potential for grease degradation and leakage into the limit switch housing had not been considered, based on the angle and higher temperatures. Interviews with maintenance personnelindicated that no oil sheen was observed when the affected limit switch was inspected; however, after cleaning, an oil sheen was observed on the cleaning tool.
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, maintenance personnel noting that no oil was seen in the housing. No source of the oil
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-13-sheen was provided. Also, an inspection of the valve was performed at the next high pressure core injection system outage. No foreign material or oil was identified in the limit switch compartment at that time.
c.
Conclusions An indication light failed on the high pressure coolant injection steam admission valve.
Subsequent troubleshooting did not identify the source of the failure or address why the other simit switches were not affected. The subsequent engineering evaluation was wer.k. Applicable industry information was not addressed, the potential effect on valve control switches was not addressed, and operability was concluded without identifying the source of the foreign material which was concluded to have caused the problem.
Significant inspector involvement was required before relevant aspects of operability were addressed.
E2.2 Control Buildino Batterv Room Temperatures Reouire Entrv into Abnormal Proceduces a.
Scoce (37551)
Inspectors reviewed the recurring condition of entry and exit of the abnormal procedure associated with low battery room temperatures. Inspectors reviewed procedures, control room logs and problem identification reports and held discussions with operators, engineers, and managers.
b.
Observations and Findinos The licensee's Abnormal Procedure 2.4.8.4.9, " Control Building Temperatures Above or Below Temperature Limits," required that operators log temperatures and, if temperatures approached the operability limit for the batteries, that portable electric heaters be used to heat the battery rooms under low temperature conditions. The inspectors verified that the heaters could be powered from either vital bus and were included in the dieselload study and fuel consumption analysis. Heaters had also been required at times during the winter months and during some outages.
The control room staff requested that engineering investigate resolution of the concem, since, for several summers, the operators have been required to implement the abnormal procedure. Temperatures must be logged, but they typically did not decrease to the point where operability was threatened and heaters must be set up. Plant management also demanded an evaluation by engineering.
Inspectors asked if the ignition source of the heaters in the open doorway was a potential risk if hydrogen generation were to occur. The procedure required a hydrogen monitor to be set up in the battery room when heaters were in service and periodic operator rounds be made to check the local temperatures and the hydrogen monitors. Also, a fire watch was required to be present at the open doorway, since it was a fire door. Operations stated that the fire watch was assigned and trained to close the door if a fire were to l
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-14-occur and was not required to monitor hydrogen generation. Inspectors reviewed the 10 CFR 50.59 evaluation for the abnormal procedure, which stated that the fire watch would be available for continuous observation of the hydrogen monitor.
Regarding the safety significance. engineers determined that the essential ventilation, which was constantly in cervice, produced several hundred cubic feet per minute of air flow turnover in the battery rooms. This volume of air would provide dilution and mixing of any hydrogen generated to maintain it well below explosive limits.
In a discussion with the ventilation system engineer assigned to resolve the problem, the engineer stated that the reason the problem occurred was that the battery capaciy was too close to the operability margin at normal temperatures. It could not maintain margin at the lower temperatures caused by chilled air ventilation during the summer. The ventilation system engineer maintained that thc concern was a result of battery design and not a ventilation problem. He did not plan to take action to correct the concern.
Inspectors found that several minor contradictions and weaknesses were associated with this concern and that the licensee had relied on a long term operator work-around to address a design problem. However, the safety significance was low since the heater loads were analyzed, redundant power sources were available, and the essential ventilation provided significant air flow turnover and mixing to preclude hydrogen generation buildup. Since this issue is being followed by the plant operator work-around program, no formal inspector followup item is required.
c.
Conclusions Although battery room temperatures have been maintained within operability requirements, the licensee enters an abnormallow battery room temperature procedure every summer since the essential ventilation keeps temperatures low enough to potentially challenge the battery operability. Procedures which required operators to set up temporary heaters when required contained minor weaknesses. Engineering has not yet provided a permanent resolution for the work-around.
E8 Miscellaneous Engineering issues E8,1 (Ocen) Licensee Event Reoort 50-298/95-10-00: maintenance of the RHR systems minimum flow bypass valves in the closed position resulted in the plant being in an unanalyzed condition.
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Description of Circumstances Condition Report 94-0466, dated August 1994, identified a concern with the required position of the RHR minimum flow valves. Several design documents were found that contradicted the current practice at the time to have the valves closed while the RHR system was in a standby line-up. In resolving these discrepancies, the licensee determined that the appropriate position of the valves should be normally open. The l
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-15-l licensee implemented Design Change 94-322 in December 1994 to change the position of the RHR minimum flow valves from normally closed to normally open. During closeout of the design change package, and resolution of Condition Report 94-0466, the licensee
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determined that the previous practice of maintaining the minimum flow valves closed placed the plant in an unanalyzed condition. As a result, the licensee made a 4-hour nonemergency report to the NRC in April 1995.
The licensee identified that, during a large break loss of coolant accident (LOCA)in a reactor recirculation loop pump discharge line, a failure of the 125V de electrical distribution bus supplying power to the minimum flow valve for the non-LOCA affected RHR loop would prevent the valve from opening. This would result in operation of the associated RHR pump (s) in a no-flow condition until reactor pressure decreased sufficiently to allow the LPCI valve to open. The licensee determined that operation of the pumps in a no-flow condition for greater than 20 seconds could result in pump damage and the inability of the pumps to perform their LPCI function. The 20 seconds was based upon the pump vendor's certification. However, data was unavailable to show that, after 20 seconds, the pumps would degrade or fail.
For break sizes of approximately 80 percent of the design basis case (a full guillotine break of the recirculation loop piping), the licensee determined that depressurization of the reactor vessel could take 30 seconds or longer before LPCI could begin injecting.
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Thus, with the loss of the 125V de electrical distribution bus supplying power to the minimum flow valve, the licensee postulated the failure of the RHR pump (s) due to the no-flow condition exceeding the 20 seconds certified by the vendor. Additionally, the failure of the 125V de electrical distribution bus would result in loss of one of the core spray pumps, leaving a single core spray pump to provide core cooling for this scenario.
A review of the licensee's current LOCA analysis found that, for a reactor recirculation discharge line break, two independent emergency core cooling system pumps are required to mitigate the event (e.g., two core spray pumps or one core spray pump and one LPCI pump). The licensee, therefore, concluded that this scenario would place the plant outside of its design basis.
Without additional plant-specific analyses, the licensee was unable to demonstrate that the above scenario, with credit taken only for a single core spray pump, would maintain peak cladding temperatures less than 2200*F. However, several mitigating factors were identified by the licensee which would indicate emergency core cooling system performance for the above scenario could be adequate. Those factors were: (1) RHR pump damage is not guaranteed when operated in a no-flow condition for greater than 20 seconds, (2) the limited break size would allow some contribution from LPCI in the broken loop, and (3) high pressure coolant injection would tend to depressurize the reactor more quickly than the existing analysis indicates, thus reducing the time the RHR pumps operate in a no-flow condition.
The licensee also noted that General Electric had performed more detailed analyses for other boiling water reactor licensees of similar vintage and design to show that a single low pressure emergency core cooling system pump was adequate to support core
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cooling. These analyses were performed with a more recent version of General Electrics proprietary LOCA analysis model than that used at Cooper Nuclear Station. However, due to the significant resources required, the licensee could not justify upgrading its own LOCA analyses with the newer code.
Root Cause and Corrective Actions The licensee determined that the root cause of the event was a failure to properly integrate the plant's design basis into the modification that removed the LPCI loop selection logic. Specifically, without the ability of the LPCI system to be selected to the intact recirculation loop, the closed minimum flow valve presented a single failure vulnerability with the loss of one of the 125V de electrical distribution busses, as described above. The failure to identify the vulnerability was due to weak management oversight and poor understanding of the design change processes.
To prevent recurrence of similar issues, the licensee credited its ongoing Design Criteria Document program :n developing detailed design criteria for plant structures, systems, and components. The compi!ation of the design criteria would provide a comprehensive reference for evaluating and implementing future design changes. The development and use of th3 design criteria documents was considered to be adequate to address the underlying concern.
During the modification to the LPCI loop selection logic, the licensee failed to identify the need to maintain the RHR minimum flow bypass valves open to protect against a potential loss of core cooling function when a single failure of a 125V de electrical bus is postulated. This licensee event report (LER) is being evaluated with similar issues regarding design control associated with the NRC architect engineering inspection. This LER remains open.
E8.2 (Ocen) Unresolved item 50-298/97008-03: Use of Teflon tape without proper engineering evaluation. After discussions with inspectors concerning Teflon qualifications, the licensee restricted Teflon usage in the plant. The licensee stated that this concern will be addressed by a final report scheduled to be issued on approximately June 17,1998.
E8.3 (Closed) Unresolved item 50-298/97005-03: Plugging of RHR B heat exchanger tubes.
This issue described a case where significant plugging of heat exchanger tubes was observed but was not properly evaluated or corrected. The NRC subsequently issued escalated enforcement for this concern in NRC Inspection Report 50-298/97-12.
Therefore, this unresolved item is closed and will be covered in followup to the escalated enforcement issued in NRC Inspection Report 50-298/97-12.
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IV Plant Support
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l R2 Status of Radiological Protection and Chemistry Facilities and Equipment R2.1 Failure to Reoort inocerable Radiation Monitor in Annual Reoort a.
Insoection Scoce (71750)
Inspectors reviewed daily operating logs, Technical Specifications requirements, and the Annual Radiation Monitoring Program Report to assess the licensee's radiation monitoring of the service water system. Inspectors held discussions with operations, radiation protection, engineering, and licensing staff.
b.
Observations and Findinas Leakage through the RHR heat exchanger service water outlet valves results in an effluent discharge of approximately 100 gpm. The service water effluent radiation monitors for the service water system were designed to function with the service water booster pumps in service, however, during normal operation, the booster pumps are secured. The resultant leakage with the system in standby is not accurately monitored.
When leakage from the service water outlet valves was identified in October 1997, the licensee recognized the need to monitor the release and the inability of the radiation
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monitor to monitor the system. The radiation monitor was declared inoperable and Technical Specifications 3.21.A.1.c, " Limiting Condition For Operations," was entered, which required collection of daily grab samples and analysis. From October 22 through December 31,1997, service water was discharged and the radiation monitors were inoperable.
Inspectors identified that the licensee had not reported in the Annual Radioactive Materials Release Report that releases had occurred with this instrument inoperable for greater than 31 days and had not explained why the problem had not been repaired in a timely manner, as required by Technical Specification 3.21.A.1.d. The licensee stated that the monitor was not designed to operate at the lower pressure service water system conditions during normal operation, and the system was designed so no release would occur when service water booster pumps were secured. The heat exchanger outlet valve leakage had not been anticipated in the origina! radiation monitor design. The implications of sustained inoperability of the radiation monitor were not fully addressed in the evaluation of service water outlet valve leakage. The inspectors considered that this problem was caused by poor material condition of the RHR heat exchanger valves.
The failure to report that this instrument had been inoperable from October 22 through December 31,1997, and to explain why the problem hao not been repaired in a timely manner, in the 1997 Annual Radioactive Materials Release Report, is a violation of Technical Specification 3.21.A.1.d, which requires, in part, that, if this instrument channel is not retumed to operable status within 31 days, in lieu of any other report, explain in the
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18-next Annual Radioactive Materials Release Report why the instrument was not repaired in a timely manner. This violation is being cited to require corrective actions to make the required report and to address the poor material condition of the valve (VIO 298/98003-03).
c.
Conclusions
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The licensee did not provide an explanation conceming why an inoperable radiation monitor was not fixed in a timely manner, in the Annual Radioactive Materials Report, as required by Technical Specifications 3.21.A.1.d. This situation was caused by operation of the service water system with RHR service water heat exchanger outlet valves
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leaking. Also, the licensee did not recognize the reporting requirements with liquid discharges occurring with the radiation monitors inoperable.
X1 Exit Meeting Summary The inspeders presented the inspection results to members of licensee management at the exit meeting on May 28,1998. The licensee acknowledged the findings presented.
The inspectors asked the licensee wheths.' eny materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED l
I-l Licensee
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l M. Boyce, Plant Engineering Manager D. Buman, Specific Projects Engineering Manager J. Burton, Performance Analysis, Manager L. Dewhirst, Licensing Engineer C. Fidler, Assistant Maintenance Manager B. Houston, Licensing Manager L. Newman, Operations Manager J. Peters, Licensing Secretary INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92700: LER Followup IP 92901: Followup - Plant Operations IP 92902: Followup - Maintenance IP 92003: Followup - Engineering ITEMS OPEN'ED, REVIEWED AND CLOSED Ooened 298/98003-01 URI Containment spray switch operability evaluation relied on manual action (Section O2.1).
t 298/98003-02 IFl Reactor equipment cooling surveillance inadequate (Section M3.1)
298/98003-03 VIO. Failure to report inoperable radiation monitor (Section R2.1)
GQ1td 298/95-05-00 LER Failure of safety reliaf valves to pass surveillance (Section M8.1)
298/97005-04 URI Criticality monitors (Section 08.1)
298/97005-03 URI Plugging of heat exchanger (Section E8.3)
Reviewed 298/98002-05 URI Failure of an emergency procedure to implement the design basis (Section 08.3)
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298/97008-03 URl'
Failure to analyze teflon before use in reactor plant systems (Section E8.2)
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