IR 05000397/1993036
| ML17290A803 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/12/1993 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17290A801 | List: |
| References | |
| 50-397-93-36, NUDOCS 9312130022 | |
| Download: ML17290A803 (49) | |
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U.S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report No:
Docket No:
..-." License No:
Licensee:
Facility Name:
Inspection at:
50-397/93-36 50-397 NPF-21 Washington Public Power Supply System P. 0.
Box 968 Richland, WA 99352 Washington Nuclear Project No.
(WNP-2)
WNP-2 site near Richland, Washington Inspection Conducted:
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September 7 October 18, 1993 Inspectors:
R.
C. Barr, Senior Resident Inspector D. L. Proulx, Resident Inspector M. H. Hiller, Senior Resident Inspector, Diablo Canyon, (10/4-10/8)
K. P. Johnston, Project Inspector (9/27-10/1)
J.
F. Melfi, Resident Inspector, Trojan (9/13-9/17)
Approved by:
P.
H.
nson, Chief Reacto Projects Section
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Date Signed
~Summau:
Ins ection on Se tember 7 - October
1993 Re ort No. 50-397 93-36 d:
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inspectors of control room operations, licensee action on previous inspection findings, operational safety verification, surveillance program, maintenance program, licensee event reports, special inspection topics, and procedure adherence.
During this inspection, Inspection Procedures 36800, 37700, 61726, 62703, 71707, 90712, 92700, 92701, 92702, 92720, and 93702 were used.
Safet Issues Mana ement S stem SIMS Items:
None.
Results:
General Conclusions and S ecific Findin s Strengths:
The Technical Specification Surveillance Improvement Program (TSSIP)
continued to perform quality reviews of TS surveillances and to identify issues (Paragraph ll.b).
9312i30022 93iii2 PDR ADOCK 05000397 PDR
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Teamwork and communications between licensee organizations appeared to have improved (Paragraph 6).
Weaknesses:
The licensee failed to submit a Technical Specifications amendment prior to implementing a design change, in violation of 10 CfR 50.59.
This indicated continuing weakness in the quality of engineering r'eviews and of reviews performed by the oversight committees (Paragraph 5).
The licensee did not appear to aggressively pursue corrective actions for a steam leak in the reactor core isolation cooling (RCIC) system identified by the inspectors (Paragraph 8.c).
The licensee's initial response and investigation for a lost TLD was weak (Paragraph 8.b(9)).
The corrective action program did not appear to have clear criteria for categorizing significant conditions adverse to quality (Paragraph 7).
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The formal root cause process appeared to be limited in scope (Paragraph 7).
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Insufficient care when working near safety-related equipment resulted in a half-scram (Paragraph 4).
Si nificant Safet Matters:
None.
Summar of Violations and Deviations:
One cited and three non-cited violations were identified.
The cited violation involved the licensee's failure to properly implement
CFR 50.59 (Paragraph 5).
The non-cited violations involved a health physics technician exceeding overtime limitations (Paragraph 8.b(9)), the untimely reporting of inoperable fire dampers (Paragraph ll.b(3)), and the incorrect consolidation of two reportable events into a single LER (Paragraph ll.b(5)).
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DETAILS Persons Contacted V.
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Parrish, Assistant Managing Director for Operations Flasch, Engineering Director Swailes, Plant Manager Baker, Technical Training Manager Hosier, Licensing Manager Smith, Operations Division Manager Mebring, Technical Services Hanager Honopoli, Maintenance Division Manager Coleman, Regulatory Programs Manager Albers, Radiation Protection Manager Rhoads, guality Support Manager Benjamin, guality Assessments Manager Davison, Plant Support Assessments Manager Peters, Administration Manager Shaeffer, Operations Manager Mann, Acting Operations Manager Barbee, System Engineering Manager Sawyer, Assistant Operations Manager Schumann, Acting Operational Events Analysis Manager Fies, Licensing Engineer Swank, Licensing Engineer The inspectors also interviewed various control room operators, shift supervisors and shift managers, maintenance, engineering, quality assurance, and management personnel.
"Attended the Exit Meeting on November 3, 1993.
2.
Plant Status 3.
At the start of the inspection period, 'the plant was at 100X power.
The plant continued to operate at 100X power (except for temporary power reductions to support control rod exercises and bypass valve testing)
until the end of the inspection period.
Previousl Ide tified NRC Ins ection Items 92701 92702 The inspectors reviewed records, interviewed personnel, and inspected plant conditions concerning licensee actions on previously identified inspection findings:
a.
Closed Violation 50-397 92-37-01 Inade uate Procedures for Develo ment of Rod Patterns During the followup inspection for the August 15, 1992 power oscillation event, the inspectors found that the procedures used for development of control rod patterns did not contain adequate qualitative or quantitative acceptance criteria.
As corrective
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actions the licensee (I) revised the responsibilities assigned to the shift technical advisors (STAs), the reactor engineers, and the fuels engineers; (2) developed detailed startup plans, which included improved procedures with objective acceptance criteria, to specifically describe operating strategies for maneuvering through the power-to-flow areas of concern; (3) issued a new plant procedure, Plant Procedures Hanual (PPH) 1.3.59, "Reactivity Hanagement Program;"
(4) took disciplinary action; (5) revised applicable startup and maneuvering procedures to reflect the new operating strategies; (6) issued a memo to all employees detailing the lessons learned from the event; (7) revised facility procedures to include a new "area of increased awareness" on the power-flow map; (8) revised applicable plant procedures to require use of the stability monitor; and (9) committed to install variable speed recirculation pumps to preclude the plant from performing the maneuvers that involve risk from a core stability standpoint.
The inspector reviewed the licensee's documentation of the corrective actions, reviewed the applicable procedure changes, and interviewed licensee personnel.
The inspector noted that the licensee did not intend to install the variable speed recirculation pumps until 1996.
The delay in completing this action does not appear to significantly affect the licensee's commitment to prevent another core instability event.
Based on the above, the inspector concluded that the licensee had taken sufficient corrective action to prevent recurrence.
This item is closed.
Closed Unresolved Item 50-397 92-37-04 Licensee Pursuin New Licensin Stabilit Code During the followup inspection for the power oscillation event of August 15, 1992, the inspectors found that the licensee's core stability code (COTRAN) used for licensing actions appeared to have several deficiencies and limitations for evaluating mixed cores and other anomalies.
This resulted in the licensee being unable to predict whether the core physics values that existed on August 15, 1992, would lead to core instability.
The licensee's fuel vendor, Siemens Power Corporation (SPC),
possessed a more thorough core stability code (STAIF) that SPC could use to evaluate certain special evolutions on request.
After evaluating the STAIF code and determining that it was also adequate for licensing actions, SPC submitted a topical report for STAIF to NRR in October 1993 for review and licensing of the STAIF code for use in core stability evaluations.
The inspector reviewed the documentation available for the submittal, and determined that the licensee had taken aggressive action to address this item.
This item is closed.
Closed Violation 50-397 92-25-02 Data Outside Test Acce tance
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This enforcement item concerned inadequate post-modification testing on the reactor core isolation cooling (RCIC) turbine control circuit through the remote shutdown panel.
The inspector found instances where the recorded voltages on Haintenance Work Request (HWR) AR8673
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deviated from the acceptable value.
Responsible plant engineering personnel said that the involved electricians called the responsible system engineer and discussed the data.
The test data were verified as acceptable by signature dated June 27, 1992.
This practice was contrary to Subsection 1.3.7.12 of Procedure 1.3.7,
"Maintenance Work Request,"
since the testing should have been stopped and the equipment returned to a condition specified by the shift manager.
The licensee acknowledged this violation in responses dated November 6, 1992, and January ll, 1993.
The licensee stated that the root cause for this event was inadequate personnel work practices by several contractor supervisors, because procedures were not followed correctly.
The licensee discussed the incident with the affected personnel and provided training to contractors on
. procedure compliance.
Based on the licensee's corrective actions, this item is closed.
Closed Violation 50-397 92-25-03 Failure to Retest Reactor Core Isolation Coolin RCIC Transfer Switch This enforcement item concerned the failure to perform a post-maintenance test (PMT} on a RCIC transfer switch after installation.
Section IV of MWR AR 4743 installed this component to transfer control of the RCIC system from the control room to the remote shutdown panel.
A PMT was necessary to verify that the new switch would perform satisfactorily in service.
The licensee satisfac-torily tested this switch after the inspector brought this issue to their attention.
e.
The licensee acknowledged this violation in responses dated November 6, 1992, and January ll, 1993.
The root cause, as deter-mined by the licensee, was that personnel work practices were less than adequate and procedures were not followed correctly.
A contributing.cause was procedural deficiencies regarding operations personnel oversight of MWRs and PMTs.
Specifically, the licensee considered the log practices for tracking in-process work status to be inadequate.
The licensee discussed this event with the affected personnel and improved the level of control provided for MWRs.
The inspector verified that the licensee had an up-to-date status of their MWRs in the control room.
Based on the licensee's corrective actions, this item is closed.
Closed Violation 50-397 92-25-05 Failure to Follow Procedures This enforcement item noted three separate instances wherein procedures were not followed.
These were:
Failing to confirm that a valve was closed in response to a discharge pressure high/low alarm, as required by Annunciator Response Procedure 4.601.A2, Revision 4.
Improper measurement of valve stroke time.
The acceptance criteria for measuring valve stroke times noted, in part, that
stroke time measurement terminates when the corresponding position indicating light becomes lit.
Accepted industry prac-tice terminates a stroke time measurement, for dual position indicated valves, after the corresponding position indication becomes lit and the opposite indication becomes unlit.
An operator did not follow the procedure or initiate a procedure deviation to allow the measurement to be done correctly.
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Failing to install a clamp-on ultrasonic flow meter during a
performance test on an air handling unit (AHU) heat exchanger.
This was required by standby service water heat exchanger test procedure PPH 8.4.79,
"Thermal Performance testing of PRA-FC-IA and PRA-FC-IB."
The licensee acknowledged this violation in responses dated November 6, 1992, and January ll, 1993.
The licensee addressed each of the specific issues cited in the violation and counseled workers on procedure compliance.
The.licensee addressed and is still addressing the overall issue of procedure compliance.
This issue is being followed up during routine inspection efforts.
Based on the licensee's actions, this item is closed.
No violations or deviations were identified.
4.
Event Followu 93702 Half-Scram Due to Dro ed Leads On September 28, 1993, during maintenance associated with AR-5321 (an HWR that performed repairs on local power range monitor LPRH-DET-48/49)
an instrumentation and controls (I8C) technician caused a reactor half-scram (i.e., resulting in one channel of the reactor protection system (RPS)
being in the tripped condition).
The event occurred at the completion of Step 9 in the HWR.
This step required that a high resistance meter be used to check cable and detector insulation resistance for the LPRH connector.
This meter had special test leads to perform this troubleshooting task.
The licensee's standard procedures placed the meter inside the rear of the cabinet near an average power range monitor (APRH) drawer, because the leads were only two feet in length.
The leads from the meter were then attached to the connector.
Following completion of that step, the leads were removed and the meter was removed from inside the cabinet.
While removing this test equipment, the leads slipped from the technician's hand and contacted terminal connections in the APRH drawer.
The technician observed a
spark, and the sound of relays changing state.
Operators received and responded to a reactor half-scram annunciator at that time.
After the event occurred, maintenance personnel opened the cabinet and inspected the alarming APRH drawer for damage.
The licensee found no damage to the drawer.
Further troubleshooting revealed that the short circuit had resulted in a blown fuse on the APRM card.
The technician replaced the fuse, then operators reset the APRM drawer, and the half scram cleared.
The licensee initiated an Incident Review Board (IRB) to
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investigate the-cause of the event and recommend corrective actions.
A problem evaluation request (PER)
was also initiated.
Licensee corrective actions included fabricating special test connectors for working on LPRHs.
The licensee also investigated other cabinets to see if similar drawers were at risk during maintenance or surveillance work.
This event was discussed with the IKC shop.
The inspector discussed this occurrence with the Plant Manager.
The Plant Manager acknowledged that this event indicated a need for more care when working near sensitive safety-related equipment.
No violations or deviations were identified.
Desi n Modification of Service Water Valves 37700 During the previous inspection period (NRC Inspection Report No. 50-397/
93-31), the inspector identified several clearance tags which did not match the nomenclature on the electrical cubicles associated with certain safety-related valves.
These valves were service water valves SW-,V-4A, 4B, 4C, 24A, 248, 24C, 44, and 54.
Due to the clearance order and communications problems noted in NRC Inspection Report No. 93-31, the inspector performed a more detailed examination of the design change package associated with these valves.
Plant modification request (PHR) 90-0361 was a design change package that converted the above listed service water valves to manually operated valves.
These valves were all normally open, motor-operated valves that were only closed for maintenance or surveillance activities.
They each received open signals for the engineered safety features (ESFs) with which the valves were associated.
PHR 90-0361 removed the cabling and control power from these motor operators and motor control centers, and the valves became locked-open, manual valves.
PMR 90-0361 was performed after the 1993 refueling outage while the plant was operating.
The inspector reviewed the engineering work in PHR 90-0361 and concluded that it was appropriate.
In addition, the package contained the many proposed FSAR amendments necessary for implementation of the modification.
The inspector reviewed the applicable top-tier drawings and noted that the drawings had been satisfactorily revised to include PHR 90-0361.
Several plant procedures also called out these service water valves.
The inspector reviewed each of these and found only one discrepancy.
PPM 2.4.10, which performs the annual operability surveillance for the remote shutdown panel, had not been revised to reflect PHR 90-0361.
The inspector discussed this apparent discrepancy with the licensee's project manager (PH).
The PM said that this surveillance would not be performed until the April 1994 refueling outage, and that PPH 2.4. 10 would be revised by that time.
The inspector concluded that the licensee's actions to revise procedures for the PHR were satisfactory.
The inspector also reviewed the safety evaluation for PHR 90-0361.
The inspector found that these valves were not only specifically listed in the FSAR as motor-operated valves, but were also listed in Technical Specification 3.8.4.3 as motor-operated valves requiring thermal overload protection.
Therefore, the inspector concluded that the licensee had
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made a change to the facility that involved a Technical Specifications (TS) change.
CFR 50.59 requires. licensees to obtain NRC approval be-fore implementing a change to the facility that requires a
TS amendment.
The failure to request a TS amendment and obtain NRC approval prior to converting SW-V-4A, 4B, 4C, 24A, 24B, 24C, 44 and 54 to manually operated valves is a violation of 10 CFR 50.59.
(Violation 50-397/93-36-01).
The inspector discussed this violation with the licensing manager.
The licensing manager stated that the Supply System interpreted the require-ments of 10 CFR 50.59 to require prior NRC approval only if the design change would result in the violation of a limiting condition for operation (LCO) or render the associated safety system inoperable.
The licensee also stated that a TS amendment for TS 3.8.4.3 was in prepara-tion, and would soon be submitted to the NRC.
Licensing personnel initiated PER 293-1250 to investigate this violation.
The inspector reviewed the Plant Operations Committee (POC) minutes in which the POC approved PHR 90-0361.
Members of the POC initially questioned implementing PMR 90-0361 without prior NRC approval.
However, the licensing manager explained the Supply System's interpretation of
CFR 50.59 to the members of the POC, which then approved PHR 90-0361 for immediate implementation.
The Corporate Nuclear Safety Review Board (CNSRB) also reviewed this design change, and did not raise any concerns with the 50.59 evaluation of PMR 90-0361.
Although the violation described above had low safety significance, because it did not affect system operability or introduce a new failure mechanism, this issue indicate a need for improvement in the licensee's
CFR 50.59 program.
The inspectors will review additional design changes during future inspections for possible similar concerns.
In addition, the inspector concluded that the quality of reviews done by the oversight committees (POC and CNSRB) warrants strengthening.
The inspector discussed the above observations and conclusions with the Plant Manager, who acknowledged the inspector's comments.
One violation was identified.
6.
Teamwork and Communications 36800 The inspector evaluated the teamwork and communications among the Operations, Maintenance, Health Physics, Plant Technical Services, Design Engineering, and guality Assurance Departments.
The inspector assessed the effectiveness of teamwork and communications involving both urgent and routine work during the months of August, September and October 1993.
In assessing this area, the inspector reviewed about 125 problem evaluation req'uests (PERs),
attended routine meetings, followed emerging operational issues, reviewed guality Assurance audit concern documents, and interviewed personnel at all levels in the organizations that were evaluated.
a.
Communicatio s
The 1993 SALP report discussed a need for various segments of the licensee's organization to more effectively communicate with and
support Plant Operations.
Based on observed management emphasis op coordination between departments during routine meetings and on information obtained during personnel interviews, the inspector con-cluded that communications between WNP-2 organizations had improved.
Of particular note were improvements in the teamwork and communica-tions of the Health Physics and guality Assurance organizations.
Health Physics involvement with other departments to minimize radiation exposure had incr eased significantly.
This increase was evident in emergent work associated with Maintenance and Operations in identification and repair of steam leaks and in involvement with Engineering in routine design change planning.
The inspector reviewed communications regarding guality Assur'ance (gA) audit-concerns between gA auditors and individuals in several organizations.
This documentation identified several cases where understanding of requirements was clarified and improper practices were identified and corrected.
This improved the focus on the need for~ a constructive, self-critical attitude concerning clarification of requirements, identification of problems and implementation of corrective actions.
Teamwork The inspector observed teamwork (i.e., the delivery of a quality product to meet the needs of another department or organization)
to exhibit some improvement.
Based on reviews of problem reports and interviews with personnel, the inspector concluded that the barriers to producing a higher quality product were the focus on production and a need for stronger commitment to procedure adherence.
"Production mentality" was a term used by licensee employees to describe an attitude of hurrying to finish a job at the cost of adherence to procedures and quality work practices.
Some Supply System employees at supervisory and working levels expressed the concern 'that pressure may be applied by direct supervision or middle management to hurry an urgent job without taking time to pay attention to detail and ensure that all requirements had been performed.
These personnel expressed frustration that once a
specific job was underway the direction of top management to follow procedures and do a quality job may be seen by supervision. or middle management as an'unacceptable delay, when considering the schedule pressure.
None of the individuals could identify where this had occurred recently, except for one instance in which a Problem Evaluation Report (PER)
was issued and the problem corrected.
Most personnel interviewed believed that senior management did not hold supervisors and middle managers accountable for avoiding a
production mentality to the extent that the lower level personnel were held accountable.
The interviewees related several instances wherein high production pressure had occurred in the past.
When questioned, the individuals could not conclusively state whether the supervisors or managers involved had been disciplined for their participation in the even ~
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Specific findings concerning the focus on production were:
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Problem Evaluation Re ort PER Process Not Likel to Identif Production Mentalit
Individuals interviewed pointed out that the PER process required validation signatures of the employee's supervisor and manager before the PER could be issued.
This could have a chilling effect on employees'dentifying instances of production mentality via the PER process.
No process was considered effective to stop the production mentality of a supervisor except to object directly to the supervisor, resulting in possible adverse consequences.
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Inconsistent Monitorin of Su ervision:
Based on personnel interviews, the inspector also noted that supervision and middle management had not been consistently monitored or clearly held accountable for restraining a production mentality in their areas of responsibility.
Supervision and middle management appeared to have been rarely held accountable in cases where equipment had failed or where random observation by senior management identified a production mentality.
In one case, employees in a different department documented a
production mentality via a PER.
The inspector concluded that the Supply System had recently improved in this area, because the majority of the individuals interviewed stated that some of the recent management and supervisor changes, positive and negative recognition, and counseling of individuals, had resulted in reduced pressure to finish a job quickly.
Lack of Pro'cedure Adherence One of the principal barriers to delivery of a quality product to other organizations appeared to be poor procedure adherence.
This was also a root cause or major factor contributing to many of the PERs.
Additionally, NRC inspector observations have continued to identify a lack of familiarity with and 'adherence to procedures.
The inspector found that each department had demonstrated instances of failure to adhere to procedures.
The inspector observed that the number of procedure deviations (temporary changes)
had increased significantly in the past few months, indicating that individuals have increased their attention to procedure adherence and stopped work when a procedure could not be performed.
The inspector found that the interviewees recognized the need for procedure adherence, indicating that management's expectation to adhere to procedures and stop work when procedures cannot be followed had been made clear.
All interviewees recognized that failure to adhere to procedure would result in some form of disciplinary action.
Interviews by the inspector indicated that some of the procedure adherence issues were the result of users not knowing that a
procedure was applicable, rather than failur'e to adhere to procedure steps.
During these interviews, a general concern was expressed by
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the working level regarding procedure adherence; specifically, that supervision and middle management were not held accountable to inform them of all applicable procedures.
As a result, failure to adhere to one of these unknown procedures could result in sanctions.
against the employee, with no allowances made for the failure of management and supervision to clarify the requirements.
When questioned further, employees did not identify specific instances where this concern had been validated, but stated that they knew it had happened on site in the past.
From the interviews, the inspector found that Supply System management had not been routinely or consistently monitoring themselves or their subordinate managers or supervisors to ensure awareness of and adherence to procedures.
d.
~Summar The inspector found that recent Supply System emphasis on. communi-cations had resulted in some improvements.
Teamwork had also improved, but appeared limited by issues associated with production mentality and weak procedure adherence, which at times interfered with delivery of a quality product to other organizations.
Several of the concerns regarding teamwork involved inconsistent monitoring and accountability of supervisory and middle management personnel.
During the exit meeting, licensee management acknowledged the inspector's findings and stated that the findings would be evaluated.
No violations or deviations were identified.
Root Cause Pro ram 92720 a ~
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Previous inspections have discussed weaknesses in the licensee's process for the evaluation of plant problems.
These findings, highlighted in the April 1993 Systematic Assessment of Licensee Performance (SALP), noted that while the licensee has done a quality job of reviewing significant plant problems and events, the review of less significant problems and events has lacked consistency and has contributed to failures in resolving repeating problems.
In response to these findings, the licensee committed to the NRC to revise the Problem Evaluation Request (PER) process, their program for problem identification and resolution.
The revised procedures governing the PER process were subsequently reviewed and approved by the Plant Hanager in late August/early September 1993 and were implemented on October 4, 1993.
The inspector reviewed the revised PER process, from the initiation of a PER to the determination of cause, during the week of September 27, 1993.
The inspector reviewed several PERs initiated in August 1993 under the previous procedures, to assess the programs strengths and weaknesses and to provide a baseline for reviewing the PER process changes.
In addition, the inspector reviewed the PER process procedure changes, the licensee's training program to support the
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-10-program implementation, and the licensee's plans for program implementation oversight.
The revised PER process shares several elements with the previous process.
The licensee's PER process covers conditions described in
CFR 50 Appendix B, Criterion XVI.
Any member of the licensee's staff can initiate a PER if a problem is identified.
The PER is then validated by a first line supervisor, reviewed by the Operations Shift Manager, and assigned to a dispositioning manager.
The problem is then categorized for significance.
For significant conditions adverse to quality or SCAgs, the licensee performs a
cause review and establishes corrective actions to preclude repetition.
For less significant conditions adverse to quality or CAgs, the PER program requires a less rigorous evaluation.
The program has some flexibilityto address problems which do not meet either criterion.
eview of P
Rs F} om Au ust 1993 The inspector reviewed a sample of 15 PERs which had been initiated in August 1993.
The purpose of the review was to obtain an understanding of the strengths and weaknesses of the previous problem identification process from the initiation of a PER to the review of the problem's cause.
The inspector did not assess the corrective actions.
The inspector selected the following PERs:
293-'1028 293-1029 293-1033 293-1046 293-1058 293-1064 293-1066 293-.1069 293-1078 293-1082 293-1086 293-1088 293-1105 293-1116 293-1119 Scram Discharge Volume (SDV) level switch inaccurate Main Steam'Relief Valve (MSRV) did not open during event when setpoint reached SDV vent 5. drain valves failed to open fully Heater Drain- (HD) hangers pulled from wall Recalibration of MSRVs performed with bad Heise gage MSRV discharge vacuum breaker o-ring failures HD system pipe supports damaged Half scram on Average Power Range Monitors (APRM)
Steam line elbow leaking Steam leak in a 1/2" steam line Condensate relief valve lifts during pump starts HD check valve air operator stuck in mid-position Non-safety time delay relay found out of tolerance Loose parts alarm Main Steam Isolation Valve (MSIV) leakage control system heaters out of specification The inspector found that the quality of the reviews was not consistent.
While some of the PERs included good reviews, all of the PERs reviewed had some aspects that which did not appear to meet management's expectations as described to the inspector.
The individual weaknesses were reviewed with licensee management for their action and are not discussed here.
The inspector did identify some common weaknesses in the implementation of the process with several of the PERs.
These included the following:
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Classification of roblem si nificance:
The PER dispositioner,
. the individual assigned to provide the review of probable cause and corrective actions, was required by the PER procedure to identify the significance of the problem.
The licensee had established four categories:
SCAg, potential CA(, other condition or suggestion, and trend only.
The PER procedure required a detailed cause review for only problems identified as a SCAg.
None of the fifteen reviewed were identified as SCAgs, 5 were identified as CAgs, six as "other," and 4 as
"trend only" The inspector found that many of the fifteen appeared to have been misclassified.
In some cases, the problems were listed as
"trend only" or "other" when a CA( existed.
The inspector did not observe that this classification had an impact on the quality of review.
However, as seen in the review of the revised procedures discussed in the next section, misclassifi-cation could have a larger impact on the quality of review.
The inspector found that between July 1 and September 31, 1993, when over 240 PERs were initiated, only eight were categorized as a SCAg.
These eight PERs included four NRC-identified Severity Level IV violations and four LERs, which were specifically required by the procedure to be considered as SCAg.
While the inspector did not find any specific examples of SCAg problems which had not been properly documented, it appeared that the licensee was initiating a minimum number of SCAg reviews.
The resolution of repeat problems, such as the heater drain system water hammer event which caused the damage described in PERs 293-1046 and 293-1066 and previously docu-mented in PER 291-956 (November 1991),
would benefit from the thorough root cause review provided in the SCAg process.
Probable Cause S eculation:
In 8 of the.15 PERs, the probable causes described were speculative in nature.
In some instances, the probable cause description recognized this speculation, and in some instances the cause was stated as fact.
As an example, PER 293-1064 noted the cause of several HSRV discharge line vacuum breaker 0-ring failures as "aging of O-rings."
The PER provided no supporting information regarding this conclusion.
Corrective actions for most of the PERs with speculative cause descriptions called for further investigation of the problem.
For example, PER 293-1064 included a corrective action to investigate the 0-ring failures.
In most PERs, this action had yet to be completed.
As a result, the actual cause of several problems had not been addressed with corrective actions.
Re eat Occurrences and Associated Events Not Referenced:
Some of the PERs which discussed problems which were repeat occur-rences did not reference the previous events.
As an example,
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-12-the inspector was informed that 0-ring failures similar to those described in PER 293-1064 had previously.occurred.
This was not referenced in the PER.
Although the pipe hanger damage discussed in PERs 293-1046 and.293-1066 was apparently caused by the same water hammer event, they did not reference each other.
Additionally, PER 293-1066 did not explore the cause of the hanger damage.
Further, neither PER referenced previous occurrences of the same water hammer (PER 291-956).
The inspector noted that the general areas of weakness described above were not specifically addressed in the revised PER procedures discussed below.
In general, these weaknesses appear to be of the type that can most effectively be addressed by management>s communi-cation of expectations through training and management oversight review.
At the exit meeting, the inspector encouraged plant.
management to improve the quality of their PER reviews.
The Plant Manager noted that it was his understanding that management reviews of PERs had improved, but that additional emphasis would be placed in this area.
Revised PER Pro ram Procedures The inspector reviewed the recently revised procedures which govern the PER process from problem initiation to review of problem cause.
The review was performed after the procedures had been reviewed and approved by the Plant Manager, but before they went into effect on October 4, 1993.
These procedures included:
PPM 1.3. 12,
"Problem Evaluation Request" PPH 1.3.12A, "Processing Problem Evaluation Requests" PPM 1.3.15,
"Plant Problem Reports" PPH 1.3.48,
"Root Cause Analysis" The inspector noted that the procedures had addressed many of the PER process weaknesses discussed in previous inspection reports and in the latest SALP report.
PPM 1.3.12 provided simple instructions and clear criteria for the initiation of a PER.
The purpose of the procedure was primarily limited to the initial documentation of a problem and as a result, the procedure was shorter and less imposing than previous revisions.
This was done to eliminate a barrier to initiating PERs.
PPH 1.3.48 provided guidance on the level of evaluation for the determination of causes for problems determined to be CAgs.
Previously, guidance for CAgs had not been provided.
For SCAgs,'he procedure provided greater flexibilityin the methodology used to determine root cause.
In addition, it transferred the primary responsibility for cause determination to the line organizatio I
- 13 The inspector noted some weaknesses in-the procedures,-
as discussed below, and.communicated these to the licensee.
The criteria for categorizing problems as CAQ and SCAQ were confusing.
PPM 1.3.12, Attachment 8.1, provided very good tabulations of potential CAQs, including some examples.
PPH 1.3. 12A provided a broader definition of "deficiency," which included CAQs.
However, the definition in PPM 1.3. 12A was not consistent in some aspects with the table in PPM 1.3.12, and it was not clear why two definitions wer'e necessary.
The licensee stated that they would evaluate these differences for
'onsistency and make appropriate revisions.
The inspector noted similar weaknesses in the definition of
- SCAg.
The definition and examples used to determine when to initiate a SCAg evaluation, described in PPH 1.3.12A, Attach-ment 8.1, were more general and appeared inconsistent with a table in PPH 1.3.48 used to determine what rigor should be used during the'ause evaluation of significant deficiencies.
The licensee subsequently revised PPH 1.3. 12A to reference the table in PPM 1.3.48 for additional examples of SCAQs.
At the exit meeting, the inspector expressed concern regarding the clarity of the categorization of CAQ and SCAQ.
As noted in the previous section, there appeared to be a trend toward identifying fewer SCAQs.
With the program changes, the dispo-sitioning manager has the responsibility for both categorizing and reviewing problems.
A manager making a less conservative call on problem significance would appear to be able to reduce the amount of followup review for which he or she would be responsible.
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As discussed above, the licensee had included instructions in PPH 1.3.48 on the cause review necessary for a CAQ.
The inspector found that these instructions were not referenced in PPM 1.3.12A, which governs the disposition of each PER step, including the cause review.
The licensee subsequently revised this procedure to provide the necessary reference.
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The inspector found that the revised procedures did not reference the licensee's procedure for Incident Review Boards (IRBs),
PPH 1.1.8.
The purpose of an IRB is to immediately investigate and establish the facts pertaining to plant events when human performance is suspected to be a main contributor, or events that have significant impact on the licensee.
, Typically, IRBs are initiated by the Operations Shift Manager or plant management shortly after a significant event.
The
, licensee concurred that the IRB should be formally considered in the PER disposition process and revised PPH 1.3.12A.
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The inspector noted that while PPH 1.3. 12 was considerably shorter and simpler than before, it included several steps pertaining to a conditional release process used to allow non-conforming parts to be used in the field pending evaluation or
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testing.
The inspector considered the discussion of.the conditional release process in the PER initiating procedure to be confusing and unnecessary.
The use of the conditional release process appeared to be limited to warehouse staff personnel and not applicable to the majority of site employees using the PER process.
The licensee agreed that it could be confusing and stated that they would evaluate moving the requirements to PPH 1.3.12A.
In general, the inspector found that the procedures were improved and should address some of the principal weaknesses previously'dentified.
However, the inspector remained concerned that the licensee's definitions of CA( and SCAg were not sufficiently clear.
d.
~Trainin The inspector reviewed the licensee's training established to imple-ment the revised procedures.
The training included the following:
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PPH 1.3.12 training:
All plant personnel expected to initiate PERs were to be provided a one-hour training session covering the instructions for initiating a PER.,
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PPH 1.3. 12A training:
All supervisors expected to fill the role of dispositioning manager were to be provided with a four-hour class covering the process for dispositioning a PER.
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Root Cause training:
The licensee has provided several root cause training programs over the past several years.
The current two-day program is designed to provide a general background in root cause evaluation techniques.
The inspector found that the training acceptably covered the appropriate topics and that management had made a large commitment to providing training to the necessary people.
e.
~0versi ht The inspector's general observation was that the success of the licensee's revised PER program would be largely dependent on the successful communication of management's expectations.
The inspector reviewed the li.censee's oversight action plans.
The licensee stated that they would take the following actions to monitor the implementation of the revised program:
The licensee planned additional management reviews of each PER disposition for the first six months of the program.
The licensee planned to review the necessity of these evaluations in January 1994.
guality Assurance planned to perform a combination of audits and surveillances to evaluate the program's succes ~
The root cause analysis group, which previously had the responsibility for SCAg reviews, planned to be involved in all SCAg reviews and will closely monitor CA( reviews.
In addition, the inspector reviewed a September 27, 1993, memorandum from the Plant Manager to all WNP-2 employees which described his expectations for the new PER process.
The inspector concluded that these plans, if fully implemented, should provide the necessary followup assessment of the PER program implementation.
No violations or deviations were identified.
0 erational Safet Verification 71707 a.
Plant Tours The inspectors toured the following plant areas
Reactor Building Control Room Diesel Generator Building Radwaste Building Service Mater Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
The inspectors observed the following items during the tours:
(1)
0 er atin Lo s and Records.
The inspectors reviewed records against Technical Specification and administrative control procedure requirements.
(2)
onitorin Instrumentation.
The inspectors observed process instruments for correlation between channels and for conformance with Technical Specification requirements.
t3) ~lif II i
.
Th i p t
b d
t
d *lift manning for conformance with 10 CFR 50.54.(k), Technical Specifications, and administrative procedures.
The inspectors also observed the attentiveness of the operators in the execution of their duties and noted that the control room was free of distractions such as non-work related radios and reading materials.
(4)
E ui ment Lineu s.
The inspectors verified valves and elec-trical breakers to be in the position or condition required by Technical Specifications and administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Technical Specifications limiting conditions for operation were verified by direct observatio ~
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-16-(8)
(9)
E ui ment Ta in
.
Selected equipment, for which tagging requests had been initiated, was obse} ved to verify that tags
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were in place and the equipment was in the condition specified.
General Plant E ui ment Conditions.
Plant equipment was observed for indications of system leakage, improper lubrica-tion, or other conditions that would prevent the system from fulfillingits functional requirements.
Annunciators were observed to ascertain their status and operability.
Fire Protection.
The inspectors observed fire-fighting equipment and controls for conformance with administpative procedures.
Plant Chemistr
.
The inspectors reviewed chemical analyses and trend results for conformance with Technical Specifications and administrative control procedures.
Radiation Protection Controls.
The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with Radiation Mork Permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
Radiation monitoring equipment was frequently monitored to verify operability and adherence to calibration frequency.
Missin thermoluminescent dosimeter TLD :
On September 27, 1993, Radiation Protection (RP) personnel identified that an individual who exited the controlled area due to an off-scale pocket ion chamber (PIC) did not have a TLD in his TLD case.
RP restricted his access until his dose could be estimated,.
and initiated PER 293-1190.
The licensee's initial corrective actions as documented in the PER included interviewing the individual on work activities, and determining the exposure of his work partners to estimate his dose.
Interviews revealed that the individual was erecting scaffolding in a fairly low radiation field.
The licensee determined that tampering with the TLD was unlikely.
Therefore, the licensee concluded that-he had bumped his TLD and PIC in a manner that caused the TLD to fall out of its casing, and caused the PIC to go off scale.
The initial PER also indicated that it was virtually impossible for an individual to receive an empty TLD case, due to the strict gA controls of the TLD issuing personnel (i.e., dual independent verification).
An additional concern that RP management raised was that the individual's TLD had been installed in his case improperly.
The part of the TLD casing that opens was supposed to be attached to the security badge clip to prevent opening.
Licensee investigation further revealed that a significant
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-17-number of personnel on site had also been issued-their TLD and badge improperly.
Therefore on September 28, 1993, RP issued an all-employee memorandum to describe how the TLDs should be installed, and how to properly wear a TLD and badge.
On September 30, while witnessing maintenance associated with AP-4364 (see Paragraph 10) the inspector noted four individuals who were not wearing their dosimetry per the above discussed memorandum.
The licensee stated that once the information was thoroughly disseminated these events would no longer occur.
The inspector questioned the thoroughness of the licensee's initial investigation, as documented in the PER, with RP management.
The inspector was concerned that the licensee had not initiated a search for the missing TLD, conducted a drift test of the PIC, or investigated the TLD i-ssue program to verify that other TLD casings contained a TLD.
Following discussions with the inspector-the licensee conducted an unsuccessful search for the TLD and a drift test on the PIC several days 'later.
Licensee i'nvestigation of the TLD issuance process found that the process did not include spec'ific verifi-cation that.each TLD case contained a TLD, but merely verified that each individual was issued a coded number.
The licensee then concluded that the issuance of an empty TLD case to the individual was a plausible (if not probable)
cause of the event.
The inspector discussed the licensee's revised conclusions with the Plant Hanager.
On October 14, 1993, while cleaning out a barrel of scaffolding knuckles, licensee maintenance personnel discovered the TLD chip that had been missing since September 27, 1993.
TLD pro-cessing personnel read the TLD and confirmed that the PIC had not gone off-scale because of overexposure.
Although, ulti-mately, the licensee was able to determine the cause of the lost TLD event and was able to positively determine the individual's dose, this event indicates'that more aggressive initial investigation (as documented in the PER)
may have been necessary.
The.inspector discussed these conclusions with plant management.
Although plant management acknowledged the inspector's comments, the licensee stated that they believed that the Supply System was sufficiently aggressive in investi-gating this event, given the circumstances.
Overtime Limitations:
On September 27, 1993, the licensee identified that a health physics technician (HPT) had exceeded the Technical Specifications limitation for overtime.
Exami-nation of his time sheets indicated that the HPT had worked 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> in a 168-hour period, without obtaining specific written permission. from the Plant Manager.
TS 6.2.2.(e)
requires individuals to work fewer than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 168-hour period, or receive specific written approval to exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> worked.
RP management initiated PER 293-1191 to document this occur-rence and propose corrective actions.
The PER indicated that both the HPT and his supervisor were aware of the TS require-
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-18-ments, but had not paid sufficient attention to detail to ensure that the overtime limits were not exceeded.
The inspector discussed this issue with the Plant Hanager, who acknowledged the need for additional steps to ensure that personnel comply with the overtime restrictions.
Licensee management more clearly defined management expectations for compliance with TS 6.2.2.(e) with their personnel.
In addition, disciplinary action was administered for the above discussed overtime violation.
Since this violation was identified by the licensee, and other criteria of Section VII.B(2) of the NRC Enforcement Policy were satisfied, this
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violation was not cited (NCV 50-397/93-36-02).
(10) Plant Housekee in
.
The inspectors observed plant conditions and material/equipment storage to determine the general state of cleanliness and housekeeping.
. Housekeeping in the radio-logically controlled area was evaluated with respect to controlling the spread of surface and airborjIe contamination.
(11) ~Securit
.
The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures, that search equipment at the access control points was operational, that the vital area portals were kept locked and alarmed, and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functional.
c.
En ineered Safet Features Walkdown The inspectors-walked down selected engineered safety features (and systems important to safety) to confirm that the'systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
Proper lubrication and cooling of major components were also observed for adequacy.
The inspectors also verified that certain system valves were in the required position by both local and remote position indication, as applicable.
The inspectors walked down accessible portions of the following systems on the indicated dates:
~Sstem Diesel Generator Systems, Divisions 1, 2, and 3.
Low Pressure Coolant Injection (LPCI)
Trains A, B, C
Low Pressure Core Spray (LPCS)
Dates October
September 10, October
September 10, October
e.
e I"I
~ 4-19-High Pressure Core Spray (HPCS)
Reactor Core Isolation Cooling (RCIC)
Residual Heat Removal (RHR), Trains
"A" and "B" 125V DC Electrical Distribution, Divisions 1 and
September
September 27, October
September 10, October
October
250V DC Electrical Distribution October
During the walkdown of the RCIC system on September 27, the inspector noted steam issuing from the lagging near RCIC-V-26.
The -inspector notified the Shift Manager and Health Physics (HP).
Four days later, when this condition still had not been documented nor had any action been taken, the inspector discussed the apparent lack of aggressiveness in resolving this issue with the Plant Manager.
Later that day the system engineer for RCIC toured the area of the leak and initiated a problem evaluation request, PER-293-1203.
The licensee then removed the lagging and located the leak.
The steam leak appeared to be coming from a socket weld near RCIC-V-26.
The licensee performed non-destructive testing (NDT) of the leaking weld to determine the failure mode, and determined that the leak was a result of pipe erosion.
Additional lagging was removed from this RCIC line, and several other welds were examined by NDT.
The Supply System found no other instances of pipe erosion.
The leaking weld was temporarily repaired by applying sealant.
The licensee intends to replace the affected piping during the next refueling outage (R9)-.
.WNP-2 personnel determined that the most likely root causes of the erosion of the piping were a leaking steam trap or leaking steam trap bypass valve.
The line associated with the leak connects to the steam line to the RCIC turbine, and drains the header through'a steam trap.
The leak was in the portion of the piping downstream of the steam trap, leading to the main condenser.
.This piping is guality Class II; therefore, the leak was of low safety significance.
However, in this instance, the licensee did not appear to initially respond aggressively to a known deficiency.
The Plant Manager acknowledged the inspector's comments.
One non-cited violation was identified.
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'urveillance Test'in 61726 The inspectors reviewed surveillance tests required to be performed by the Technical Specifications (TS),
on a sampling basis, to verify that:
(1)
a technically adequate procedure existed for performance of the surveillance tests; (2) the surveillance tests had been performed at the frequency specified in the TS and in accordance with the TS surveillance requirements; and (3) test results satisfied acceptance criteria or were properly dispositione \\
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-20-The inspectors observed portions of the following surveillance tests on the dates. shown:
P d
I~I Dates Performed 7.4.6.1.3.2 7.4.1.3.1.2 7.4.7.9.4 7.4.2.1 Containment Personnel Airlock Leak Rate Test Control Rod Exercises Weekly Bypass Valve Testing Surveillance of Core Power Distribution Limits September
September
September
October
No violations or deviations were identified.
10.
Plant Maintenance 62703 During the inspection period, the inspector observed and reviewed
'ocumentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance'procedures, required QA/QC involvement, proper use of clearance tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector verified that reportability for these maintenance activities was correct.
The inspector witnessed portions of the following maintenance activities:
Descri tion Dates Performed PPM 10.12.24, Calibrate RHR-FT-13 AR-2252, Fuel Pool Cooling Drain Line Modifications AP-5325, Install Stainless Steel Tubing at Instrument Rack Connec-tions for RPV Level Purge AP-5321, Repair Local Power Range Monitor LPRM-DET-48/49 AP-4364, Install Final Cabling and Terminations for Reactor Pressure Vessel (RPV) Level Purge AR-5356, Troubleshoot and Repair Wide Range Neutron Monitor
'No violations or deviations were identified.
September
September
September 24-25 September
September 29-30 October
t ta-21-Licensee Event Re ort LER Followu 90712 92700
The inspector reviewed LERs associated with operating events during this inspection period.
a ~
In-Office Review The inspector reviewed the following LERs associated with operating events.
Based on the information provided in the reports it was concluded that reporting requirements had -been met, root causes had been identified, and corrective actions were appropriate.
The inspectors closed the following LERs based on in-office review:
LER NUMBER 93-20 93-21 93-23 93-24 93-25 93-26 b.
On-Site Followu DESCRIPTION Improper Scheduling of Hain Steam Relief Valve Position Indicator Testing Containment Atmospheric Control System Water Accumulation and Potential Containment Bypass Improperly Supported Instrument Flexible Conduit Containment Instrument Air System Actuation During System Restoration Engineering Safety Feature Actuation Caused By Surveillance Testing Failure to Complete Weekly Battery Surveillance Requirements Within the Allowed Technical Specification Interval Due to a Scheduling Oversight The inspectors reviewed the following LERs by on-site followup of the details contained therein:
(1)
Closed LER 93-10 Revisions
1
3 and
Technical S ecification Surveillance Im r ovement Pro 'ect Identification Of Non-Conformin Conditions As part of the corrective actions identified in LER 91-013, Revision 2, the licensee started a Technical Specification Surveillance Improvement Project (TSSIP).
The TSSIP revised and broadened the scope of the Surveillance Procedure Veri-fication Program completed in May 1991.
A total of nine reportable problems identified by this process were described in this LER and its revisions.
All nine issues relate to failure of procedures to fully implement WNP-2 Technical Speci-fications surveillance (TSS) requirements.
This LER reports the initial findings of the TSSIP surveillance procedure review process.
Based upon previous experience with the Surveillance
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-22-Procedure Verification Program, it is likely that additional reportable items will be identified.
The licensee intends to supplement this LER, as necessary, to describe future reportable items.
t The inspector discussed the TSSIP with the program manager to understand the progress made to date.
This program is described in procedure 1.5.1,
"Technical Specification Surveil-lance Testing Program."
The manager noted that they were about nine percent complete and had identified nine instances of inadequate surveillance.
The inspector noted that the TSSIP has identified numerous improvements in the TS surveillance program.
Several of these have involved surveillance procedures which did not properly implement TS surveillance requirements.
In each of these cases, subsequent performance of the required surveillance tests showed equipment to be operable.
Based on the scope and results to date of this ongoing licensee program, Revisions 0 through 4 of this.LER are closed.
Closed LER 93-13 Revision
Loss Of Containment Inte rit Due To A Reactor Core Isolation Coolin S stem Sin le Failure Criteria Violation On Harch 18, 1993, a design error was identified by Supply System engineers working on the Component Safety Classification Program.
The reactor core isolation cooling (RCIC) system pump suction line from the suppression pool did not meet single failure design criteria.
A failure of Division 1 direct current (DC) power to the RCIC system would cause the motor operators for the pump suction isolation valve (RCIC-V-31) and the auxiliary cooling water supply valve (RCIC-V-46) to fail in a non-conservative position.
The licensee resolved this problem by changing the valve from
'C power to alternating current (AC) power.
This change eliminated the potential release path due to a single failure.
In discussing the safety significance of this LER, the licensee stated that this fission product release scenario could also have been eliminated by analysis.
Their analysis showed that the RCIC system would not be called upon to operate for a large break LOCA, and that a fission product release should not occur following a small break LOCA.
In view of the modification installed and analysis performed by the licensee, this LER is closed.
Closed LER 50-397 93-17 Revision
Fire uglification Concerns Identified in 1985 Throu h 1987 Not Re orted This LER described the failure to report in 1985 and 1987 that safety-related fire dampers would not have functioned as designed during a seismic event.
Because the LER did not fully describe why this deficiency, as described in nonconformance report (NCR) 285-0543, was not reported in accordance with 10
04 ~
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-23-CFR 50.73 and
CFR Part 21 until 1993, the inspector performed followup inspection.
While the licensee told the inspector that in 1987 it considered this deficiency potentially reportable, the licensee did not at that time have time constraints for resolving potentially reportable issues.
The licensee also noted that until changes were made to Part 21 in 1992, there was no clear Part 21 reporting requirement fot this type of deficiency.
In NRC Inspection Report No. 50-397/92-36, the inspectors found that the licensee had lost track of several Part 21 and
CFR 50.73 reportability evaluations.
To address this concern, the licensee established a plan to disposition these evaluations.
The subject of this LER was one of the issues in which the licensee had not performed a.timely reportability assessment.
The'icensee has since changed procedures to require that a
determination be made on a potentially reportable issue within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
CFR 50.73(a)(v)(D) requires that an LER be submitted within 30 days for a condition that alone could have prevented the fulfillment of a safety function required to mitigate the consequences of an accident.
Inoperability of the fire dampers in a seismic event meets this reportability criterion and should have been reported within 30 days.
The failure to report this problem within 30 days is an apparent violation of
CFR 50.73(a)(v)(D).
Because the licensee satisfied the cri-teria specified in Section VII.B(2) of the Enforcement Policy, this violation is not being cited (NCV, 50-397/93-36-03, Closed).
0 en LER 50-397 93-22 Revision
Two Control Rods Withdrawn With Their Scram Accumulators Ino erable This LER described a violation of Technical Specification action 3.1.3.5.b, which requires that control rods with inoperable scram accumulators be inserted and their associated control valves be electrically or hydraulically disarmed.
The inspector performed on-site followup inspection because the licensee's determination of root cause and proposed corrective actions appeared incomplete.
The LER did not adequately describe why operators did not correctly interpret TS 3. 1.3.5.b and did not fully discuss that administrative controls were implemented that should have prevented this event, even though the accumulators had not been disabled.
In the LER the licensee concluded that the event had the following two root causes:
plant procedures did not provide guidance to assure that inoperable control rods are disarmed, and the faulty scram accumulator level switches were not repaired in a timely manner.
However, in discussions with licensee personnel and in reviewing support documentation for
-24-(5)
the event, the inspector found that the formal root cause evaluation performed by the licensee's root cause group was different from the root cause in the LER.
This group concluded that the root cause was operator error.
The inspector also noted that the TS clearly require the inoperable control rods to be either electrically or hydraulically isolated.
The Shift'Hanagers maintain a limiting condition for operation (LCO) log which,lists inoperable TS equipment.
Each relieving Shift Hanager is required to review -this log prior to assuming the shift.
At the time of this event, the LCO log indicated that the control rods which the operators moved were inoperable.
Therefore, had the licensed operators adequately reviewed the LCO log they would have known that the control rods were technically inoperable and should not have been moved.
In reviewing the Plant Operating Committee (POC) minutes of August 24, 1993, the inspector found that the discussion did not intrusively probe the operators'ack of understanding of the TS, the use of the LCO log, or the corrective actions proposed by the LER.
The inspector noted that in January 1993, a violation of the TS occurred because the Shift Hanagers had not adequately reviewed the LCO log.
The licensee acknowledged the inspector's observations and committed to provide, additional information to clarify the rationale used in obtaining the root cause described in the LER.
This LER remains open.
Closed LER 50-397 93-27 Revision
Reactor Scram Durin Hain Steam Line Hi h Radiation Channel Calibration This LER described a reactor scram that occurred on August 3, 1993.
The scram resulted from a maintenance workmanship error on the dual solenoid pilot valve of a main steam isolation valve (HSIV).
Followup of that event was described in NRC inspection report 50-397/93-31.
The LER adequately described that event.
The LER also described an event that was separate from the reactor scram.
On August 5, 1993, a system engineer identified a small steam leak upstream of valve HS-V-22.
The licensee concluded that the leak was reactor pressure boundary leakage and was reportable per
CFR 50.72 and
CFR 50.73.
The licensee notified the NRC as required by 10 CFR 50.72, but did not submit a separate LER for the event as required by 10 CFR 50.73.
CFR 50.73 requires that unrelated events be reported sepa-rately.
Because the pressure boundary leak was not associated with the reactor scram of August 3, 1993, that event should
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-25-have been reported by a separate LER.
This is an apparent violation of 10 'CFR 50.73 (NCV, 50-397/93-36-04).
The inspector discussed this requirement with members of the licensing organization, who concurred with the inspector and committed to submit a separate LER.
The licensee also'eminded staff personnel involved with LER preparation that unrelated events must be addressed by separate LERs.
Because the cri-teria specified in Section VII.B(l) of the Enforcement Policy were satisfied, this violation is not being cited Two non-cited violations were identified.
lR.
~Eit N ti The inspectors met with licensee management representatives periodically during the report period to discuss inspection status, and an exit-meeting was conducted with the indicated personnel (refer to paragraph 1)
'on November 3, 1993.
The scope of the inspection and the inspectors'indings, as noted in this report, were discussed with and acknowledged by the licensee representatives.
The licensee identified the topical report and. review schedules for the STAIF core stability computer code (discussed in-paragraph 3.b.)
as proprietary.
This inspection report contains no proprietary informatio I0 tVg