IR 05000277/1989026
| ML20012D129 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 03/14/1990 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20012D120 | List: |
| References | |
| 50-277-89-26, 50-278-89-26, NUDOCS 9003260501 | |
| Download: ML20012D129 (58) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report No.:
50-277/89-26 License No. DPR-44 50-278/89-26 DPR-56
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Licensee:
Philadelphia Electric Company
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Correspondence Control Desk P. O. Box 7520 Philadelphia, Pennsylvania 19101 Facility Name:
Peach Bottom Atomic Power Station Units 2 and 3 Dates:
November 20 to December 31, 1989 Inspectors:
J. J. Lyash, Senior Resident Inspector R. J. Urban, Resident Inspector L. E. Myers, Resident Inspector G. Y. Suh, Project Manager, NRR S. V. Pu11ani, Senior Operations Engineer ch d
3!I 4 Approved By:
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L. T. Doerflein, fhief Da'te Reactor Projects Section 2B Division of Reactor Projects Areas Inspected:
Routine, on-site regular, backshift and deep backshift inspection ~(182 hours0.00211 days <br />0.0506 hours <br />3.009259e-4 weeks <br />6.9251e-5 months <br /> Unit 2; 238 hours0.00275 days <br />0.0661 hours <br />3.935185e-4 weeks <br />9.0559e-5 months <br /> Unit 3) of Unit 2 and 3, operational safety, radiation protection, physical security, control room activities, licensee events, surveillance testing, engineering and technical support activities, and maintenance.
Principal licensee management representatives contacted during the inspection are listed in Attachment I.
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9003260501 900313 i
PDR ADOCK 05000277 i
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Executive Summary Peach Bottom-Atomic Power Station Inspection Report 89-26 Violations 1.
During the period four incidents involving reactivity control occurred and were attributable to licensed operator failure to follow rod sequence instructions.
In each case the rod worth minimizer functioned to prevent any significant deviation from the required rod pattern.
Licensee manage-ment responded promptly to these events. However, the multiple examples in a short period are a source of concern (NV4 278/89-26-02, Section 1.3).
Because significant management attention and corrective actions were implemented by the licensee, no written response is required.
2.
A review conducted in response to an allegation identified 2 examples of failing to properly document quality control (QC) inspection activities.
Similar problems had been identified by the Quality Assurance Department.
staff prior to the allegation. Because the general problem had been identified by the licensee, and corrective actions are already being implemented, these examples will be treated as a Non-Cited Violation. The inspection findings indicate the continued need for improvement in the area of modification /QC interface (NCV 278/89-26-05, Section 10,0).
Unresolved Items 1.
A review of the Operations Incident Investigation system was performed, While the current system provides the framework for an effective process, l-in many cases there appears to be a significant delay before meaningful investigation is conducted.
Due to the high number of reports initiated and the limited resources applied to followup, a large backlog of outstanding reports exists (UNR 277 and 278/89-26-01, Section1.2).
2.
During the inspection period the licensee identified a design deficiency potentially impacting the ability to safely shutdown the plant in the event of a fire in the reactor building. The-resolution of the deficiency and the root -cause for failure of the original analysis to identify it will be reviewed during a future inspection (UNR 277 and 278/89-26-03, Section 2.8).
3.
A review of post-modification acceptance testing conducted on the cooling water supply for the core spray pump motor oil coolers identified several discrepancies, indicating the need for revision and more rigorous imple-mentation of controlling program procedures (UNR 277 and 278/89-26-04, Section 3.0).
4.
An inspection in response to an allegation was conducted. Additional
review of the acceptability of voiding a Corrective Action Request associated with modification 2106 is required to resolve this issue (UNR 277 and 278/89-26-06, Section 10.0).
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Executive Summary (continued)
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Strengths 1.
Management follow-up~and corrective action implemented following two
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equipment isolations on November 20, 1989 was thorough and well directed (Section 2.1).
2.
Coordination, preparation and conduct of maintenance act'.vities associated with replacement of the feedwater master controller and repair of a-feedwater header instrument line leak were effective and resulted in
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smooth implementation (Section 5.0).
3.
Licensee management approach to operation of Unit 2 and startup of Unit 3
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displayed a conservative, safety-conscious philosophy (Section 8.0).
Weakness 1.
Licensee Event Report 2-89-30 did not accurately describe the state of the containment boundary, and did not provide a clear description of the event root cause (Section 9.0).
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TABLE OF CONTENTS
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1.0 Plant Operations Review (71707)..............................
1.1 Operational Safety Verification / Station Tours..........
1.2 Operations Incident Investigation System Review.........
1.3 Reactivity Mismanagement Incidents......................
2.0 Follow-up of Plants Events (93702)...........................
2.1 Unit 3 Reactor Water Cleanup (RWCU) System Isolation.....
2.2 Unit 3 Shutdown Initiated Due to HPCI and RCIC Inoperability.........................................
2.3 Unit 2 Shutdown Due to Steam Leak.......................
2.4' Limited Actuation Capability of the Emergency Sirens....
2.5 Unit 3 Shutdown Initiated Due to CS and RHR Cooler LowFlow..............................................
2.6 Unit 3 HPCI System Inoperable...........................
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2.7 Unit _2 Scram During Average Power Range Monitor Surve111ance..........................................
2.8 Unit 3 Appendix R Design Deficiency....................
2.9 Unit 3 Main Steam Line Flow Transmitter Failures........
3.0 Engineering and Technical Support Activities (37828).........
4.0 Surveillance Testing Activities (61726, 71707)...............
5.0 Maintenance Activities (62703)..........
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6.0 Radiological Controls (71707, 83750, 84750)..................
7.0 Physical Security (71707, 255104)............................
8.0 Assurance of Quality (40500).................................
9.0 Review of Licensee Event Reports (90712, 92700)..............
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10.0 Allegation Fo11ow-up.........................................
11.0 Previous Inspection Item Update (92702)......................
12.0 Managemen t Meeti ngs ( 30703)..................................
12.1 Prelimic.ary Intpection Findings.......................
12.2 Management Meeting on November 29, 1989...............
Attachment I Persons Contacted Attachment II Facility and Unit Status Attachment III Licensee Handouts From the November 29, 1989 Management Meeting
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DETAILS 1.0 plant Operations Review During the inspection period Unit 2 remained in power operation.
One plant scram due to a technician error during surveillance testing, and one forced plant shutdown due to leakage from the packing of the reactor core isolation cooling system injection check valve occurred.
Unit 3 remained i
in the startup mode during most of the period reaching 70% power. Main feed water pump problems delayed the power ascension. A detailed chronology of plant events occurring during the inspection period is included in Attachment II.
1.1 Operational Safety Verification / Station Tours The inspector completed NRC inspection Procedure 71707, " Operational Safety Verification," by direct observation of activities and equip-
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ment, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status and limiting conditions for operation (LCO), and evaluation of licensee corrective actions.
The inspector reviewed logs and records for accuracy, completeness, significant operating changes and trends, correct equipment status, jumper log validity, conformance with LCOs, and proper reporting.
The inspectors performed 160 total hours of on-site backshift inspection time, including 43 hours4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br /> of deep back-shift and weekend tours of the facility.
The resident inspectors implemented extended shift coverage during the initial phases of Unit 3 startup and periodically during the remainder of the reporting period.
Inspectors focused largely on the performance of the control room staff and the effectiveness of p
communications between operations and other parts of the organiza-tion.
In general, operator performance in response to plant transients was commendable.
Performance of more routine evolutions, such as control rod manipulation reflected inattention to detail.
Communications within the control room and with other departments were generally effective.
1.2 Operations Incident Investigation System Review During late 1988 the licensee implemented a process to identify, investigate and recommend corrective actions in response to plant operational incidents.
The process is described in the Operations Management Manual (0MM), Section 14, Incidents.
The types of occur-rences requiring generation of an incident report, the scope and depth of review, the content of the final report and the flow path for closure are described. The system outlined in the OMM generally addresses the factors needed to ensure corrective action in response to event F
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Typically, the Shift Technical Advisor (STA) prepares a draft inci-dent report.
The Operations Supoort Group collects the draft report, performs the follow-up investigation, develops corrective action recommendations, and preoares the final incident report.
Each report
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is reviewed by the Operations Superintendent and Plant Manager prior to closure.
Reports meeting a certain significance threshold are
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also reviewed by the Plant Operations Review Committee.
In order to close an incident report, follow-up corrective actions must be agreed upon, but need not be complete. Their completion is tracked by a second licensee commitment tracking system.
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The inspector reviewed the licensee's procedure, discussed its implementation with plant operators and members of the support staff, and reviewed a sample of currently open, and closed incident reports.
The individuals contacted had a clear understanding of the types of problems requiring issuance of an incident report.
Final reports reviewed by the inspector generally reflected good analysis and
included appropriate corrective actions.
At the time of the inspection the licensee had a backlog of about 90 incident reports which had been generated but not closed. These 90 were distributed among the various stages of investigation, documentation and review. Approximately 30% were in final draft or in the review and closure pro-cess. A significant portion of the remaining reports, however, had received little evaluation. A delay of about 2 to 3 months from incident occurrence to the point where meaningful review is performed is inherent. While clearly significant issues are treated promptly, many other problems which may be symptomatic of weaknesses remain in the back-log.
For example, Incident Report 3-89-37 identifies a case in which a safety-related power supply lead was improperly restored, despite several levels of review. The lead had been lifted and a red blocking tag applied.
Following completion of the associated work the lead was verified and independently verified as having been relanded. The block-ing permit was reviewed by a third individual to ensure that all tags had been cleared, and was closed.
Subsequently, on November 3, 1989, it was found that the lead had not been relanded and that the original red blocking tag was'still in place. At the time of the inspector's review no substantive investigation had been performed during the intervening 2 months.
In this instance 3 levels of control and review failed to identify that the system had not been properly restored. While no plant transients or equipment actuations resulted, this occurrence warranted prompt follow-up to establish the likely root cause, the scope of the problem
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J and short-term corrective actions.
In-response to the inspector's question the Operations Support Engineer initiated follow-up review.
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A reactor water cleanup high temperature isolation occurred
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on November 20, 1989.. The isolation resulted because the j
operating shift was unaware that a cooling water valve was t
in an~ abnormal position. The licensee's response to this isolation was thorough and well conducted.
However, 12 days
. prior to the November 20 isolation, Incident Report 3-89-040 was issued documenting that the cooling water valve position was abnormal and that it had not been properly tracked.
It also warned that because of this configuration, an isolation had been narrowly avoided.
Effective short-term action to highlight the potential problem may have prevented the November 20 isolation.
The present licensee Incident Investigation System represents an improvement over the previous program, and forms the basis fo: a workable approach. Implementation of follow-up analysis, documenta-tion and trending are the part-time responsibility of two Operations Support Staff engineers; therefore, resources available to address these issues are limited.
Little initial screening to identify short-term actions which can be implemented pending issuance of the final report, or prioritization is done.
Reports are generally worked off as time is available.
It appears many of the items resulting in operations incident reports are actually maintenance or engineering issues.
The incident report provides a convenient follow-up mechanism.
The operations staff assigned to the program do not have the resources or the expertise to address all these issues.
The licensee recently approved a Nuclear Group Administrative Pro-cedure (NGAP) titled Investigation of In-House Events."
This NGAP
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establishes a substantially strengthened incident follow-up system with review responsibility appropriately distributed throughout the organization.
Included is the creation of a dedicated Event Investigation Coordinator to administer the program, and requirements for individual training in root cause analysis techniques. Although the NGAP has been approved, the actual implementation of the program may not occur for some time.
The licensee stated that additional resources would be allocated to review and disposition the current backlog of incident reports, and that a screening process to evaluate short-term action and to assign priorities would be put in place.
Due to the large backlog and the uncertainty of the time frame for NGAP implementation, this issue remains unresolved pending review of licensee corrective actions.
(UNR 277/89-26-01).
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l 1.3: Reactivity Mismanagement Incidents During the inspection period four reactivity mismanagement incidents occurred attributable to licensed operator (LO) failure to follow-
procedures.
In each case, the rod worth minimizer (RWM) functioned to prevent any significant deviation from the required rod pattern.
Unit 2 control rod withdrawal is controlled by Procedure GP-2-2,
"Startup Rod Withdraw Sequence Instructions," Revision 4.
Unit 3 control rod withdrawal is controlled by Procedure GP-2-3, "Startup-Rod Withdraw Sequence Instructions," Revision 4.
Unit 2 control rod
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insertion is controlled by Procedure GP-3-2, Revision 3, " Shutdown Rod Insertion Sequence Instructions." Unit 3 control rod insertion is controlled by Procedure GP-3-3, Revision 1, " Shutdown Rod Inser-tion Sequence Instructions." Appendix 1 of each procedure specifies
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by numbered steps the movement of each control rod in sequence and
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position.
Reactivity manipulations require the complete attention of the operators involved. To aid in this, shift management has implemented
. provisions to minimize distracting activities. These provisions include assigning a second operator to assist in monitoring the balance of the unit during control rod movements, _ and support during reactivity changes by a reactor engineer (RE).
However, it appears-that control room distractions and a lack of sensitivity to the importance of reactivity manipulation resulted in several contol rod manipulation errors during the period. Four examples are discussed below.
1.
On November 24, 1989, during the startup of Unit 3, withdrawal of Group 1 and 2 control rods to notch 48 had been completed and withdrawal of Group 3 started.
Group 3 rods were to be with-drawn from position 00 to 04. The first control rod in the group, 22-59, was withdrawn to notch 02.
The operator was distracted at notch 02 of the withdrawal and returned several minutes later. Contrary to Procedure GP-2-3 he then attempted to withdraw the control rod to position 48.
(The previous group had been withdrawn to 48). A RWM block stopped the withdrawal at position 08.
The operator suspected a failure of the RWM and requested the reactor engineer (RE) to examine the RWM.
The RE discovered the control rod misposition, and the rod was properly positioned. The Shift Manager discussed this event with the operator at the end of the shift. No entries were made in the control room log books.
2.
On November 25, 1989, during startup of Unit 3, control rods were being withdrawn to establish the desired heatup rate. The Technical Specification (TS) heatup rate limit is 100 degrees Fahrenheit (F) per hour.
The licensee administrative limit is
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80 degrees F per hour.
Cautions are included to monitor heatup rate every 15 minutes and to maintain it less than 20 degrees F for'the period.
- When the operator assigned to control rod withdrawal assumed thel task, the next group i'i the sequence were peripheral rods. The operator, believing these rods to have low reactivity worth, withdrew the first 2 rods from position 12 to 48. 'The heatup
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rate increased from about 50 degrees F per hour, to 25 degrees F in the following 15 minute period. Although not in immediate jeopardy of exceeding the average hourly limit, the operator was concerned with exceeding the 20 degree per 15 minute guidance.
He inserted control rods 14-11 and 46-51 to the full in position of 00, exceeding the insertion limit at position 12. A RWM block prevented additional rod movement.
He did not consult with the Chief 0.oerator or Shift Supervisor prior to inserting the rods-because of the perceived urgency. The two rods were subsequently repositioned to position 12.
This incident was not entered in the control-room legs.
The operator indicated that he had fully inserted the rods because he believed past training had recommended full, rather than partial insertion.
In fact, full insertion is recommended with the unit'at higher power levels; however, with rod sequence constraints in effect, it is not acceptable.
3.
On December 9, 1989, with Unit 3 in the run mode the operator withdrew all Group'34 control rods to position 02 except one which was left at 00.
Contrary to procedure GP-2-3 the operator withdrew a rod in the group from position 02 to 04, an RWM block was received. The control rod position was corrected.
In addition to control rod withdrawal the operator was also moni-toring and responding to alarms, and maintaining the unit's radio communications.
The operator stated that he lost track of which rods he had pulled from 00 to 02.
4.
On December 11,1989, Unit 3 was in the startup mode, with 2 bypass valves open in preparation for turbine roll. The oncoming shift was preparing to increase power by~ control rod withdrawal to support the main turbine startup.
The operator continued in the rod withdrawal procedure to Group 40 where the last shift had stopped. After reviewing the form he selected the first rod for withdrawal and a RWM select block was received. He reselected the rod and received the block again.
He asked the RE to examine the RWM for failure.
The RE investigated and told him it was operable.
The operator reselected the rod, received the error light and called for assistance from the second operator. After reviewing the pull
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sheet, the operators discovered that the Unit 2 startup proce-dure and rod sequence sheets had been used, rather than the Unit 3 procedure.- Previous shifts had been using GP-2-2, Appendix 1, rather than GP-2-3, Appendix 1. Investigation revealed that the
startup sequences are exactly the same until Group 40.
The RWM i
program and pull sheets for both units diverge at this point, y
hence the RWM block.
Once the error in procedure was recognized the correct instruc-tions were used and power increase proceeded without event. The licensee immediately investigated the cause of the incident and
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initiated an Incident Report.
Licensee investigation found that when Unit 3 restart commenced
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the operator could not find a copy of GP-2-3, Appendix 1, in the
"consumables" file. Instead the procedure was copied from the
"GP". controlled procedures book. The procedures that are common are white, and unit specific procedures are color coded either yellow (Unit 2) or green (Unit 3).
Unfortunately, the copies contained in the book were not color coded, and the operator pulled and copied the wrong unit instructions.
Several opera-tors, Shift Managers, Shift Supervisors, STAS, and REs reviewed the instructions and did not note the error.
Each incident, if considered individually is of minor safety-significance.
However taken collectively, in light of the short period of time in which they occurred, these incidents indicate a potential underlying weakness which warrants thorough evaluation. The inspector informed the licensee that the above described examples of failure to follow General Operating Procedures GP-2-3 and GP-3-3 constitute a violation of NRC requirements (NV4 278/89-26-02).
One additional reactivity mismanagement problem occurred during the period.
On December 4, 1989, with Unit 2 at 55.3% power, a group of eight control rods was withdrawn to position 24. The 00-11, PCIOMR Monitoring Program, indicated that the preconditioning envelope had been violated.
The reactor
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engineer (RE) had intended to withdraw all the rods in the group to 48, the full out position. When the preconditioning envelope was violated,
.the RE instructed the operator to immediately insert the rods to position 00 and he contacted Fuel Management in Corporate Engineering.
It was discovered that Fuel Management had transmitted an incorrect control rod pattern to Reactor Engineering.
The group of rods involved showed on the transmitted pattern as blank, which is interpreted as position 48, when the target position should have been 00.
The error was not discovered in the verification process. The procedure for transmittal and review of rod patterns was not adequate.
Preconditioning violations occurred only
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on barrier fuel, therefore it is expected that no fuel degradation or leakage would be caused by the error. The licensee has taken action to ensure better communications rad an effective review of future control rod pattern transmittals. These saions include transmitting intermediate and full power rod patterns together to allow comparision, modifying the transmittal form so that fully withdrawn rod positions are marked rather than left blank, and requiring a more comprehensive pattern verification.
Licensee management clearly recognized the potential significance of these
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events and initiated corrective action and a series of investigations.
l Operations management discussed each incident with the Shift Managers to ensure that expectatio'. regarding attention-to-detail and procedure adherence were understood. Operating shift crews were also briefed.
In addition to the Operations Incident Reports a separate root cause evalu-ation was undertaken by the Independent Safety Engineering Group (ISEG).
ISEG examined each event and has recommended a series of long-term cor-rective actions, including operator training additions and improvement in event follow-up practices. A corporate task force was also formed to review the incidents at Peach Bottom along with a similar incident at
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Limerick. The task force report was not available at the close of the inspection. The Nuclear Review Board (NRB)' requested presentation of the root cause analysis and corrective actions at an NRB meeting.
During this meeting, conducted immediately following the inspection period, NRB directed that additional analysis be performed with an update report scheduled for the February meeting.
Treatment of the problem at this high level in the organization provides assurance that corrective actions implemented to date will be assessed for effectiveness, and any appropriate additional long-term actions will be identified.
Because aggressive pursuit of root cause and corrective action by the licensee is evident, no written response to this violation is required.
~2.0 Follow-up of Plant Events The inspector evaluated licensee response to plant events to ensure that prompt analysis was performed, reasonable root causes were identified, and appropriate corrective actions were implemented.
In each case, the inspector reviewed applicable administrative and technical procedures, interviewed personnel and examined the affected systems and equipment.
2.1 Unit 3 Reactor Water Cleanup (RWCU) System Isolation j
During a Unit 3 startup on November 20, 1989, two RWCU system isola-tions occurred.
The control room operating staff was unaware that the cooling water supply to the RWCU nonregenerative heat exchanger had been throttled from its normally full open position, to nearly closed. As the plant heatup progressed the reactor water temperature increase surpassed the cooling capability of the heat exchanger, and i
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resulted in a high temperature isolation.
Cooling water flow was increased and the isolation reset..The control room operator, pressed by the need to monitor other ongoing activities, diverted his attention-from monitoring RWCV temperature. A short time later a second high temperature isolation occurred.
Cooling water flow was again increased and the isolation reset without further. incident.- A complicating factor was that the control room alarm which would have actuated to provide early warning of the increasing temperature was i
out of service.
The licensee reported the two isolations via ENS as primary containment isolation system (PCIS) actuations.
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the licensee withdrew the notifications, concluding'that this trip is an equipment protection feature, and not a PCIS function.
Licensee management follow-up to the November 20 incident was aggres-sive and thorough.
Shortly after the isolations a plant shutdown was initiated due to unrelated equipment problems. During the_ shutdown individual interviews were conducted and the failure to properly
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understand, track and highlight abnormal equipment status was identified as the underlying root cause. A plant status sheet was developed to provide operators with a mechanism for highlighting abnormal equipment status not readily observable from the control room. The Operations Support Staff will assist with implementation of the status sheet. The Superintendent of Operations issued a letter to a'll control room operators explaining management's expectations concerning the monitoring of equipment status.
In addition, the Superintendent of Operations and the Plant Manager personally discussed the incident with each control room shift.
Prior to restart the licensee rereviewed all outstanding maintenance items to ensure that the potential impact of all such items was clearly understood and prioritized.
The inspector reviewed the 1-icensee's corrective actions and attended the associated management review and shift briefing sessions. Overall licensee response to this incident reflected a concern for identifying root cause. Corrective actions implemented appear to be effective.
2.2 Unit 3 Shutdown Initiated Due to HPCI and RCIC Inoperability On the evening of November 26, 1989, the reactor core isolation cooling (RCIC) system failed the 150 psig flow test system initia-l tion. The pump minimum flow valve is designed to open on system initiation, and then reclose after exceeding the low flow setpoint.
Due to air entrapment in the flow switch the minimum flow valve i
continuously cycled, even with the pump at rated flow.
The licensee declared RCIC inoperable.
The operating shift determined that the high pressure coolant injection (HPCI) system could not be tested as required by the Technical Specification (TS) Action Statement, and a plant. shutdown was initiated.
The NRC was informed via ENS.
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Subsequent review ider.tified that HPCI testing could be performed and the shutdown was terminated pending completion of the testing.
Early on November 27, 1989, the HPCI 150 psig flow test was performed, and a minimum flow valve problem similar to that previously identified on i
RCIC was identified. HPCI was declared inoperable and a plant shutdown was initiated as required by TS.
The NRC was informed via ENS.
The licensee vented the affected flow switches, the HPCI flow test was successfully completed, anti the plant shutdown was terminated, i
The RCIC trip solenoid failed during testing and additional repairs were required before returning the system to operation.
Surveillance test data indicated that both HPCI and RCIC would have been capable of delivering rated flow to the reactor, even with the minimum flow valve open.
In both cases the systems had been previously filled, vented, and operated. The-source of the air could not be specifi-cally identified. The problem has not recurred on either system during several subsequent performance tests.
The inspector had no further questions.
2.3 U' nit 2 Shutdown Due to Steam Leak On November 26, 1989, with the unit at 100% power, a steam leak was discovered on Unit 2 reactor core isolation cooling (RCIC) system injection check valve A0-22. The steam was leaking from the packing surrounding the-hinge pin stem. The check valve is part of the primary containment boundary and is located in the outboard main steam isolation valve room. The leakage rate was not quantified, but was conservatively assumed to be in excess of allowable limits.
Since A0-22 is between the inboard and outboard primary containment isolation valves, the penetration could not perform its intended containment isolation function. The licensee entered Technical Specification (TS) Action Statement 3.7.0.2.d. which required the
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reactor to be'in hot shutdown in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Power was reduced and a manual scram was initiated.
Follow-ing the scram a secondary containment isolation occurred as expected due to vessel level shrink. A 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS phone call was made to the NRC.
The reactor was placed in c.old shutdown on November 27. The old packing was removed, the stem was cleaned and lubricated, and the valve was repacked.
The valve was pressurized with air and no leaks were found.
The cause of the steam leak was mechanical failure of the packing, possibly due to stress from the hinge pin stem during operation of the air operator. A0-22 is included in the preventive maintenance program ana requires packing inspection every second refueling outage for signs of degradation. The valve is a Rockwell tilting disc testable check valve and has had a poor maintenance history.
In addition, position indication is not reliable and the air operator j
does not always work. This type of check valve is also used in the
l high pressure coolant injectior. (HPCI) and core spray (CS) systems, i
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The residual heat removal (RHR) system uses an Atwood & Morrell swing check valve that has been more reliable. The licensee has approved modification 1498 to replace the Rockwell check valves with the type
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used in the RHR system. The work is scheduled for implementation during the next refueling outages for both units,
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The inspector reviewed the maintenance work package, modification meeting minutes, design drawings, inservice testing program, final mfety analysis report, and technical specifications. Corrective actions were adequate and the planned modification should enhance the reliability of the RCIC, HPIC and C% testable check valves. The inspector had no further questions.
2.4 Limited Actuation capability of the Emergency Sirens On November 27, 1989, the licensee reported that none of the 76 emergency sirens located in the 10 mile Emergency Planning Zone (EPZ)
could be activated. The licensee made a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> ENS phone call to the NRC reporting a major loss of emergency communication capability.
The problem was first noted by the Peach Bottom Emergency Response Coordinator who noticed garbled messages on the software central processor in the lechnical Support Center (TSC).
Troubleshooting by I & C technicians found a dead battery in the processor such that
' activation of the sirens from the TSC was not possible.
However, it was later determined that activation of the sirens was possible by the five surrounding counties. The system was last tested operable on November 1 during routine monthly surveillance testing.
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In accordance with Peach Bottom emergency response procedures, activation of the sirens is made by the counties after they are notified by the licensee. Activation of the sirens from the TSC is not normally done. However, this feature is tested during monthly surveillance testing.
The sof tware central processor was shipped to the manufacturer's repair facility. The battery and several damaged printed circuit boards were replaced.
The unit was returned to Peach Bottom, installed, and tested operable on December 6.
A backup software central processor was purchased from the manufacturer (Motorolla).
The licensee is developing a modification to upgrade the entire software system.
The inspector spoke with emergency response personnel, the I&C technician involved, and the system engineer during his followup.
The inspector noted that the system engineer was unaware of the problem.
In response to the inspector's concern the Maintenance
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Engineer evaluated the communication problem and determined that corrective action was needed. The system engineer.now receives a monthly system status report.
In addition, communications have been improved between the system engineer and I & C.
The inspector had no further questions.
2.5 Initiation of a Unit 3 Shutdown Due to Core Spray and RHR-
Cooler Low Flow Early on December 1, 1989, all Unit 3 core spray (CS) pump motor oil coolers failed their quarterly flow rate test. The licensee declared both CS loups inoperable, and informed the NRC vis ENS that a plant shutdown was required by Technical Specifications. A plant shutdown was already in progress due to primary coolant chemistry problems.
The licensee continued the reactor shutdown, placing the mode switch in shutdown later that day.
Each CS pump motor oil reservoir contains a cooling coil supplied during accident conditions by the emergency service water system.
Because the cooling water systems at Peach Bottom are open cycle, piping corrosion and plugging has historically been a problem.
Surveillance test (ST) 21.5-3, "ESW Flow Test," uses the differential pressure (dp) measured across an inline throttle valve to calculate the flow through the cooling coils.
The test was established to periodically verify acceptable flow and to trend system degradation.
A minimum required flow of 4 gpm was included as acceptance criteria in the ST 21.5-3.
During the modification acceptance test process, analysis by engineering supported reduction of the minimum flow criteria to 2 gpm, however, the ST had not been revised to reflect this information. Two of the 4 coolers exhibited flows of less-than 2 gpm during the ST.
It was determined that the method of flow measurement using the dp data was inaccurate.
Following the shutdown the licensee developed an alternate test method using cooling water and oil temperatures to calculate the heat removal capability of the coils.
Retest using this method was performed on both units with all coolers testing satisfactorily. Additional inspector review regarding this issue is contained in Section 3.0 of this report.
2.6 Unit 3 High pressure Coolant Injection (HPCI) System l
Inoperable On December 7, 1989, with the unit at 3% power, the Unit 3 HPCI
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system was declared inoperable when tne HPCI turbine hydraulic stop valve failed to open during the manual start test. The HPCI hydraulic oil system relief valve (RV-9214) was lifting, preventing the stop valve from opening due to a lack of oil pressure. The licensee made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS call to the NRC.
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y The licensee entered Technical Specification 3.5.C.2, which allowed reactor operation for seven days, provided other emergency core-cooling systems and the reactor core isolation cooling (RCIC) system are tested immediately and are operable. The pressure setting for RV-9214 was set to the correct value, retesting was performed, and r
the system was declared operable on December 8.
The cause of the event was a loose locknut on RV-9214, which allowed the pressure setpoint to drift from 85 psig to about 40 psig. The cause of the loose locknut is not'known.
No pressure adjustments were made to the relief' valve during.the outage. The relief valve was removed twice, once during a system flush and again during replacement of the auxiliary oil pump.
Possible jarring during these activities could have loosened the locknut since it was not mechani-cally secured in place. The licensee inspected the shaft driven
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lubricating oil pump relief valve and its lockrut was secure.
Both relief valve locknuts on the Unit 2 HPCI system and a similar type relief valve on Units 2 and 3 RCIC systems were inspected and were secure.
To prevent recurrence, the relief valve locknuts will be mechanically secured in place with wire.
In addition, surveillance test (ST)
21.3, " Adjustment of HPCI Overspeed Trip Reset Time," will be revised so that the auxiliary oil pump discharge pressure will be verified prior to unit startup after an extended outage, and monthly during power operation as part of the routine system performance test.
The HPCI shaft driven oil pump discharge pressure is already monitored on a monthly basis during power operation by ST 6.5 F-3, "HPCI Pump, Valve, Flow, Cooler."
During his followup, the inspector reviewed surveillance procedures, P& ids, spoke with the system engineer, and walked-down the Unit 3 HPCI system.
The inspector concluded that corrective actions were adequate.
2.7 Unit 2 Scram During Average Power Range Monitor Surveillance On December 21,1989, Unit 2 automatically scrammed when the second of 2 (B & D) Average Power Range Monitors (APRMs) was inadvertently removed from the " operate mode" by a technician during performance of a routine surveillance. This resulted in one APRM in each of the 2 reactor protection system subsystems inoperable, and completed the logic needed to initiate the scram.
During the transient, reactor vessel level decreased below the low level scram setpoint causing a secondary containment isolation and standby gas treatment system initiation. Water level continued to decrease towards the double low level trip setpoint resulting in initiation and injection by the high pressure coolant injection
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X (HPCI) and reactor core isolation cooling (RCIC) systems, and initiation of the alternate rod insertion system.
In addition, all 3 reactor feedpumps tripped several seconds.after initiation of NPCI and RCIC.
Reactor water level reached a low of about -45 inches and was quickly recovered.
The main steam isolation valve triple low level setpoint was not reached during the transient, and the main condenser remained available throughout the event. Within a few.
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minutes a feed pump was returned to operation.and HPCI and RCIC were removed-from service. Also during the scram a single control rod.
settled at position 02, and was manually inserted to position 00.
The licensee declared an Unusual Event (UE) at 6:07 p.m. in response
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to the valid emergency core cooling system initiation signal and injection-into the reactor vessel.
The NRC was notified of the event via the ENS at 6:11 p.m..
The licensee subsequently terminated the UE at 6:40 p.m. after returning the plant to a normal configuration.
Due to another surveillance test in progress, the HPCI system was aligned with its suction from the torus at the time of the initiation, resulting in injection of torus water into the reactor vessel.
The
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plant remained in cold shutdown for several days to allow completion of_the licensee's post-scram review and correction of primary coolant 1 -
chemistry problems caused by the torus water injection and the scram.
The B & D_APRM mode switches are adjacent and easily mistaken. The licensee revised the APRM surveillance procedure to include bypassing the channel not involved in the test k g if possible. The licensee is also considering adding use of a temporary physical barrier to prevent inadvertent operation of the second APRM if bypass is not possible.
Evaluation of the feedwater system response during the transient identified that the pumps tripped on low suction pressure.
Feedwater demand increased following the scram due to level shrink.
Feedwater control system response is believed to have been faster than histori-s cally observed, due to improvements implemented during the last outage.
This resulted in a dramatic increase in flow and a low suction pressure trip after expiration of a 7 second delay. The licensee is implemen-ting a modification to stagger the time delays to trip the A, B and C pumps at 7, 12 and 15 seconds, respectively.
The licensee determined that worn stop piston seals were the reason for settling of the rod at position 02 rather than 00.
This problem has occurred at other BWRs, and has been analyzed by General Electric.
The worn seals do not affect rod scram motion between position 48 and 04.
Failure of the rod to insert the final 2 notches does not adversely affect tt.e unit shutdown margi p
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The inspector reviewed the licensee's post-trip _ report, attended the associated Plant Operations Review Committee meeting and discussed the event with plant management and staff.
Licensee follow-up was comprehensive and the. inspector identified no concerns.
i 2.8 Unit 3 Appendix R Design Deficiency-On December 22, 1989, the licensee notified the NRC via ENS of discovery of a design deficiency affecting the ability to safely shutdown Unit 3 in the event of a fire in the reactor building.
Fire area 13N encompasses the north side of the Unit 3 reactor building, all elevations.
In the event of a fire consuming this area, the only i
source of makeup water to the reactor is the reactor core isolation cooling system (RCIC).
Licensee engineers identified that electrical cables and breakers associated with the containment isolation valves on the reactor water cleanup (RWCU) system suction line, and-the RWCU l
letdown line isolation valves were all located within the 13N fire
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area.
Spurious opening or failure to close these valves would result in an uncontrolled ioss of coolant from the vessel.
This_ loss of
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inventory would exceed the makeup capability of the RCIC system, i
rendering this path to safe shutdown ineffective.
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The licensee immediately established a roving fire watch in the area.
An engineering evaluation supporting the adequacy of a roving fire
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watch as a compensatory measure was prepared by the corporate engi-
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neering organization and approved by PORC. The inspector reviewed the.
evaluation and attended the PORC meeting. No concerns were identified, j
Additional engineering evaluation of the deficiency and development
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of potential solutions is ongoing.
The inspector will review the
licensee's final technical analysis and resolution, assessment of the root cause for failure of the original analysis to identify the weakness, and compliance with Appendix R during a future inspection (UNR 278/89-26-03).
2.9 Unit 3 Main Steam Line Flow Transmitter Failures On December 30, 1989, Unit 3 received an alarm in the control room indicating that a failure of a main steam line (MSL) flow transmitter had occurred. Unit 3 was in the run mode at 70% power.
I&C tech-nicians were dispatched to the local panel that houses the trip /
calibration units for the flow transmitters.
The master trip units for two MSL flow transmitters (DPT-3-2-116C; "A" main steam line and DPT-3-2-117C; "B" main steam line) indicated that gross failures had occurred. The indicators were below 0 psig and attempts to locally reset the gross failure trips were unsuccessful.
According to Technical Specification (TS) Table 3.2.A, a failed channel must be tripped or a load reduction must commence so that the l
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MSL isolation valves are shut within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Approximately one hour after receipt of the gross failure alarm, the primary containment isolation system (PCIS) channel (A channel, Group I) was tripped.
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After completion'of initial troubleshooting activities by the licensee, the problem was tiaced to the Rosemount transmitters (Model'
1153).
Due to concerns regarding the possibility of a spurious Group I isolation, the licensee determined that resetting the tripped channel prior to valving out the. defective transmitters would be more conservative than working on the system with a one-half Group I isolation'present. When the
"A" channel was taken out of the tripped condition, a load reduction was commenced in accordance with TS Table 3.2.A.
At this point the licensee made a one hour ENS phone call to
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the NRC reporting a TS required shutdown. After the transmitters were valved out of service, the "A" channel trip was reinserted and the plant shutdown was halted.
The above sequence was repeated when the replacement transmitters were valved back into service for calibration and functional testing.
The system was declared operable on December 31.
The licensee believes that the transmitter failures are caused by metal particles in the sensor oil, that over time align to cause a short circuit. Both transmitters were sent off-site to Rosemount for destructive testing in order to verify the failure mode. This type of failure has been observed at other facilities. Two transmitters-on Unit 2 failed in this manner in July 1989.
The inspector reviewed a failure analysis report, P& ids, electrical schematics, and reportability evaluations.
The inspector also spoke with operations and I&C personnel, and observed the installed master trip units and the replacement transmitters.
Licensee actions were adequate and the inspector had no further questions.
3.0 Engineering and Technical Support Activities The licensee has experienced problems with corrosion and blockage of the Emergency Service Water (ESW) Systera.
The system is open-cycle, drawing suction directly from the river. A series of modifications to replace suspect piping and to reduce the likelihood of future blockage is mostly
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complete on Unit 3 and is planned for Unit 2.
During the recent outage the majority of the Unit 3 ESW distribution piping was replaced by Modifi-cation 2106.
The core spray (CS) pump motor lubricating oil reservoirs are cooled by ESW. The licensee previously determined that these cooling coils were partially plugged. Due to the unavailability of replacement coils they
were not replaced.
In order to verify adequate flow and to provide a
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. method for periodic surveillance, Modification 2106 installed throttle
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valves'and instrument taps in the supply piping.
In this manner flow rate could be determined from the pressure drop (dp)'across the throttle valve.
The Modification Acceptance Test (MAT) for this portion of Mod 2106 utilized the newly installed equipment to verify acceptable flow, and included flow measurement using sonic detectors to validate the data.
When the MAT was performed all 4 CS oil coolers failed to meet the estab-lished 4 gpm acceptance criteria and the MAT results were determined to be unacceptable. The site technical staff implemented a second, informal test to measure oil temperature, and inlet and outlet' cooling water tem-peratures with the pumps in operation.
This data was used by engineering to determine the actual cooler heat transfer rate. Using the known maximum permissible oil temperature a new acceptance criteria of 2 gpm was estab-
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lished. The MAT results were subsequently presented to the Plant Operations Review Committee (PORC) and were accepted.
PORC minutes indicate that this acceptance was based on the revision of the acceptance criteria from 4 to 2 gpm.
The inspector reviewed the engineering calculations supporting the revised criteria and identified no concerns.
The inspector reviewed the data collected during the MAT,.and the surveil-lance tests in place on both units to periodically assess possible deg-radation and raised the following concerns:
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Because of the low flow rates involved the MAT data showed poor agreement between the sonic and dp measurement methods, and appeared inconsistent and potentially inaccurate.
The intent of this portion of the modification, to install a reliable system for periodic flow verification, was not met.
In addition, the data indicated that at least I cooler flow rate was less than the revised criteria of 2 gpm.
PORC accepted the MAT despite these problems, b)
Review of Unit 3 surveillance testing indicated that the same inac-curate measurement method would be used to periodically evaluate the system for degradation.
No quantification of flow had been done or was planned for the Unit 2 coolers, even though previously collected data indicated flows of less than 2 gpm existed.
Discussions with PORC members indicated that actual PORC acceptance was based on the informal operating performance test, not on the ability to verify system flow accurately.
PORC members felt that the performance test demonstrated the ability of the cooler to perform its cooling func-tion. While this is true, PORC accepted results which indicated that the
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relied upon method for flow measurement was inacurate, and that one com-ponent did not meet the established engineering acceptance criteria. The MAT results were not the basis for accepting the Modification and no documented alternate basis was generated.
Surveillance testing was not reevaluated in light of the problem and was not revised.
Failure to
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revise the surveillance procedures led to the initiation of a Technical j
Specification required plant shutdown as described in Section 2.5 of this report.
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The licensee's administrative procedures for control of modifications and
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acceptance testing include a requirement for preparation of a MAT report describing test _results,' identifying discrepancies and providing the basis for their resolution.
This report is to be presented to and approved by PORC, However, in practice a separate report is not prepared for all mods.
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Rather, issues are discussed by PORC and the PORC minutes are relied upon
for documentation. This creates the potential, as in this instance, for acceptance of results without a complete assessment of their meaning.
Also, administrative procedures do not contain provisions to ensure that surveillance tests written under the assumption that the modification will i
be successful are reevaluated following completion of the MAT to ensure that they are still valid.
In response to the inspector's concern the licensee's technical staff, with support from the engineering department, developed a procedure for per-s formance testing of the coolers.
The test uses oil and cooling water temperatures to verify that the heat removal capability of the coil is-adequate.
This test was performed on both Unit 2 and Unit 3 successfully, and will be reperformed periodically until an alternate measurement technique can be developed. The licensee also committed to implement the following actions:
a)'
Administrative Procedure A-14, " Plant Modifications," will be clari-fied, and practices changed to require that separate MAT reports providing assessment of the modification and justification for MAT result discrepancies will be prepared prior to initiation of the PORC review, b)
A-14 will also be revisca to ensure review of affected STs following completion of the MAT, c)
A review of Unit 3 MATS performed by the technical staff during the outage will be conducted to identify any additional cases in which results were not appropriately dispositioned and STs revised.
These actions appear to address the concerns raised. This issue will remain unresolved pending completion of the licensee's review and revision of the administrative control procedure (UNR 277/89-26-04).
4.0 Surveillance Testing The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators
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were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test acceptance criteria were met.
Daily surveil-lances including instrument channel checks, jet pump operability, and control rod operability were verified to be' adequately performed.
Parts of the following tests were observed:-
ST 1.1, HPCI Logic System Functional Test, ST 3.8.2, Shutdown Margin, ST 6.5.F-3, Unit 3 HPCI Pump, Valve, Flow and Cooler Functional Test ST 6.11.F-3, Unit 3 RCIC Pump, Valve, Flow, and Cooler Functional Test, ST 10.4, Relief Valve Manual Actuation, SI 3N-60, Weekly APRM' Functional Test, RT 5.31, Crossaround Relief Valve Setpoints, RT 8.17.3, Unit 3 HPCI Flow Controller Stability Test, RT 8.18.3, Unit 3 RCIC Flow Controller Stability Test, No concerns were identified.
5.0 Maintenance Activities Feed Water Master Controller Replacement During the inspection period the licensee experienced problems with the Unit 3 master feedwater controller.
During a reactor power increase the controlier failed to maintain reactor water level resulting in a 13 inch decrease and a low level alarm. The operators promptly took manus 1 control and restored level. Maintenance Request Form (MRF) 8911031 was initiated to replace the controller. Although the component is not safety-related, improper operation or error during replacement could initiate a loss of feedwater transient. The inspector monitored licensee preparations for the controller replacement and observed the changeout in the control room.
The' replacement device was thoroughly bench tested, and was energized on
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the bench for an extended period prior to its installation.
Control room operators were briefed on the evolution and, with input from operations management, implemented precautions to ensure that any inadvertent short during the replacement would not cause a feedwater transient.
Post-maintenance testing included initiation of a slight level perturbation to monitor controller response. The inspector considered licensee prepara-i tion and conduct of this evolution well planned and implemented.
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Feedwater Pump Discharge Header Instrument Line Leak Repair On December 26, 1989, a steam leak was discovered on the Unit 2 "C" feed-water pump discharge line flow instrument sensing line. The leak was from a 3/4 inch crack in the butt weld attaching root valve RTV-2-6-4115CL s
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J to the line. The area where the leak was found is between two of the four main steam lines and had radiation levels of about 5 rads per hour on contact and 1 rad per hour general area. The area is a locked high
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' radiation area at power and there was little space for inspection and repair.
Prior to inspection of the cracked weld, a power reduction was initiated to reduce radiation' levels. After examination, repair personnel made an entry to take measurements in order to construct a leak seal.
apparatus.
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The Plant Manager was concerned with repair personnel safety and the possibility that the repair activities could cause catastrophic failure of the weld due to the heavy leak seal apparatus that would be clamped on the-line. On the morning of December 27, the Plant Manager, Maintenance Supervisor, and the inspector made an entry to examine the cracked weld
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and the area.
The licensee performed a thorough evaluation of the job including mock-ups, safety support, health physics (HP), as low as reasonably achievable (ALARA) planning, mock-up training, and pre-job briefing.
The Plant Manager discussed the repair plans in two separate meetings, one of which -
was held just before the ALARA briefing. Discussion regarding the need-to reduce power concluded that the work could be done safely at 70% power.
The inspector attended each meeting and also attended training, the ALARA briefing, and the safety meetings. The entry and repair were done quickly due to mock-up traini_ng and pre-job planning. The ALARA dose estimate for the-job was 6 man-rem. The repair was completed with 4.5 man-rem. The inspector noted that Operations Shift Manager was not updated regarding the repair plans until minutes before the job was to start.
The Shift
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Manager held up the job to brief the control room crew.
The shift was well rehearsed in expectations, parameters to carefully observe, and what to do if a transient would occur before the Shift Manager would allow the repair to proceed. Overall this maintenance activity was well planned and i
controlled.
Additional Observations The inspectors also reviewed administrative controls and associated documentation, and observed portions of work on the following maintenance activities:
Document Equipment MRF 8911333 3A RFP Lube Oil Relief Valve MRF 8911268 RTV-2-06-41154CL, Root valve repair on "C" feedwater discharge header Administrative controls checked, included blocking permits, fire watches and ignition source controls, QA/QC involvement, radiological controls,
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plant conditions, Technical Specification LCOs, equipment alignment and turnover information, post-maintenance testing and reportability.
Documents reviewed, included maintenance procedures (M), maintenance request forms (MRF), item handling reports, radiation work permits (RWP),
raterial certifications, and receipt inspections.
No additional concerns were identified.
6.0 Radiological Controls 6.1 Routine Observations During the report period, the inspector examined work in progress in both units and included a review of health physics procedures and controls, ALARA implementation, dosimetry and badging, protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and materials.
The inspector observed individuals frisking in accordance with HP procedures. A sampling of high radiation area doors was verified to be locked as required.
Compliance with RWP requirements was verified during each tour.
RWP line entries were reviewed to verify that personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements.
No unacceptable conditions were identified.
6.2 Respiratory Protection Equipment Re-Inspection Concern During the inspection period a plant worker suggested to the inspector that the licensee was nut following proced re when re-inspecting respiratory protective equipment (RPE) cevices. In response the inspector reviewed applicable procedures and interviewed responsible licensee health phys'~s personnel and contract respiratory protection support personnel (RPSP).
The mobile RPE cleaning facility was relocated late in November 1989.
After relocation, the facility was not returned to service due to construction schedule problems. The RPE facepieces used during the outage were cleaned, surveyed for fixed and removable contamination, inspected, bagged in polyethylene bags and then placed in long-term storage.
The facepieces have 30 day expiration dates. When ongoing usage depleted the in plant supply, the licensee then re-inspected
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stored RPE devices and restocked the issue points as needed.
The Respiratory Protection Administrator (RPA) oversees the the RPE cleaning facility. The RPA verbally instructed the RPSPs that re-inspection of long stored RPE devices only required inspection, and not a repeat of the contamination survey.
Apparently, the RPA failed to communicate his justification for not re-surveying the
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The inspector reviewed procedure HP-515, " Inspection, Maintenance and Repair of Respiratory Protection Equipment," Revision 2, and the
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surveillance test procedures (ST) referenced in HP-515.
The STs were adequate but only addressed audit of RPEs for expiration date, but gave no direction concerning re-inspection. HP-515 provides inspec-tion guidance but lacks clarity, and does not specifically address re-inspection and therefore is subject to interpretation. When this was brought to the attention of the licensee, the immediate et.rrec-tive action was to clarify re-inspection requirements in step 7.1.1.
of the procedure.
The RPSPs were trained regarding the change. The licensee stated that HP-515 will be placed on the review scheoule for rewrite to improve clarity of the entire document. The RPA was counselled for giving verbal interpretations to personnel without discussing the basis of the interpretation.
Survey of facepieces during re-inspection is not required. The licensee has had no facial contamination, no positive nasal swabs or whole body counts which would be indicative of a problem. The licensee does perform occasional surveys; however, they are not procedurized and are infrequent and irregular. The licensee stated that the practice of random surveys during reinspection would be considered for incorporation into HP-515.
The inspector had no further questions.
6.3 Contamination Event After Unit 2 Scram On November 26, 1989, the inspector witnessed a Unit 2 forced shutdown due to an unisolable leak outside primary containment (See Section 2.3).
At 30% power the unit was scrammed which is standard practice for shutdowns.
Following observation of control room activities, t h inspector toured the reactor building (RB) approximately one and one half hours after the scram.
On reentry to the control room, the inspector
alarmed the personnel contamination monitor indicating foot contami-nation. The areas the inspector had toured were surveyed immediately for contamination.
It was determined that previously clean areas adjacent to the reactor water cleanup (RWCU) pump rooms were now contaminated and a local air monitor (AMS-3) was indicating a peak of 8000 counts per minute (cpm) on the chart, with no alarm.
The alarm set point for the AMS-3s in the plant is generally 6000 cpm.
The contaminated areas were isolated, posted and subsequently decontami-nated. Tho licensee began an investigation to determine the cause of the AMS-3 failing to alarm.
A Radiological Occurrence Report (ROR)
was initiated 12 days after the event, following questioning by the inspector.
Before the investigation was complete, another similar contamination event occurred on December 21, 1989, after another plant scram (See
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Section 2.7).
Both scrams caused a RB ventilation isolation. When RB ventilation was restarted after the scram, contamination in the RWCV pump rooms was blown into clean areas because of momentary positive pressure.
After the second event the Health Physics, Operations, Technical, and Radioactive Waste groups conducted a joint investigation.
The licensee determined that failing to decontaminate the RWCU pump rooms after maintenance and operator inexperience in restarting the ventilation system caused the events.
RWCU pump room decontamination was per-formed and additional operator guidance regarding ventilation system operation was issueci.
The inspector concluded that immediate corrective actions following the December 21 incident by the Health Physics group were adequate.
The issuance of a ROR 12 days after the first event, however, was not timely. Also, the licensee did not perceive the first contamination event to be significant. The investigation of the AMS-3 failing to alarm was not complete by the close of the inspection period. This investigation, including the ROR and long-term corrective actions will be examined in the next resident inspection report.
7.0 Physical Security The inspector monitored security activities for compliance with the Security Plan and associated implementing procedures, including:
security staffing, operations of the CAS and SAS, checks of vehicles to verify proper control, observation of protected area access control and badging procedures on each shift, inspection of protected and vital area barriers, checks on control of vital area access, escort procedures, checks of detection and assessment aids, and compensatory measures. No inadequacies were identified.
7.1 Fitness-for-Duty Training Sessions (TI 2515/104-255104)
On June 7, 1989, the Commission published the final rule and state-ment of policy on fitness-for-duty (FFD) programs for commercial nuclear power reactors (10 CFR 26). The effective date is January 3, 1990. Appropriate FFD awareness training for employees, supervisors, and escorts is required by the Rule. The inspector attended selected FFD training sessions to determine whether required training is being conducted.
The licensee has two FFD training courses; one for supervisors and a combined course for general employee awareness and escorts.
The inspector attended the combined course on December 21, 1989. All onsite supervisory courses were complete prior to issuance of this TI, and no future near-term supervisory courses are scheduled. The inspector reviewed the supervisory course lesson plan and found it to be adequate in that it outlined areas required by the Rul r-
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Overall the combined course provided a solid introduction to basic
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fitness for duty issues.
Several areas were not covered or were only briefly covered in the combined FFD training course. They included:
-- Drug and alcohol hiding places.
-- Licensee actions against employees who refuse to submit to drug or alcohol tests.
-- Testing notification methodology,
-- The FFD policy for corporate personnel who do not require unescorted site access,
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-- Collection methods or procedures.
-- Provisions for individuals selected for testing when absent for work,
-- Employee rights were briefly discussed but protection of information was not.
The inspector concluded that the combined course was good for escort training but only fair for general employee awareness. The PEco policy on drugs and alcohol was not supplied as a handout for the class.
The inspector noted, however, that other vehicles such as company and site newspapers have been used to advertise the program.
Additionally, the licensee has maintained a FFD policy for some time, so that exhaustive training may not be required.
7,2 Illegal Drug Found During Drug Search i
On November 28, 1989, while doing a random drug dog search of the protected area the dog found a positive indication of drugs in a housekeeping closet in the Modification Building.
Only trace amounts of the substance were found.
The employee responsible for the area viewed the activity and immediately left the site. The individual's access to the plant was cancelled by the licensee pending interview. A licensee investigator conducted the interview later that evening.
The employee admitted to off-site illegal drug use but denied transporting drugs on-site. The individual was permanently denied access to the plant. The inspector had no further questions.
8.0 Assurance of Quality Management Assessment of Ongoing Performance The licensee was challenged during the period for the first time since 1987 with the operation of 2 units.
Unit 2 generally operated at or near 100% power, and experienced 1 scram and a forced shutdown. During this time Unit 3 was in the startup mode ascending in power.
The Unit 3 startup was complicated by a number of technical, equipment and chemistry problems which required several power reductions and plant shutdowns. Of
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particular note was the burden placed on the operations shifts and department management due to the number of planned and unplanned plant transients.
The inspectors attended daily plant status meetings, special and routine
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PORC sessions, and plant management status review meetings. A dedicated Unit 3 Startup Readiness Assessment was conducted by the licensee, with results of the assessment being presented to licensee senior management prior to placing the mode switch in startup. The inspector also attended the Unit 3 80% power Management Oversight Team (MOT) meeting.
The MOT assessments were preplanned parts of the power ascension program.
Presentations during the meetings appeared honest and constructive.
Licensee management consistently displayed a cautious, safety conscious approach to technical issues, and appeared sensitive to the pace and complexity of demands on the organization.
For example, following the forced shutdown of Unit 2 on November 26 and Unit 3 on December 1, licensee management elected to restart Unit 3 at a later time to reduce the challenge to the plant staff.
Periodic Meeting With Quality Assurance Department Management On December 19, 1989, the resident inspectors met with the General Manager, Nuclear Quality Assurance and members of his staff to discuss QA Department activities. An overview of the QA organization, functional responsibili-ties and staffing was provided.
Discussion topics included the recently established Independent Safety Engineering Group, the licensee's corrective action processes, QA audit and surveillance scope and schedules, and a wide variety of licensee QA sponsored initiatives. The discussions were informative. A regularly scheduled monthly meeting is planned to ensure that QA management is aware of NRC concerns impacting QA and also to provide a forum for discussion of QA initiatives and their progress.
9.0 Review of Licensee Event Reports The inspector reviewed LERs submitted to the NRC and verified that appro-priate corrective action was taken and responsibility was assigned, that continued operation of the facility was conducted in accordance with Technical Specifications, and did not constitute an unreviewed safety question as defined in 10 CFR 50.59.
Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewed.
LER No.
LER Date Event Date Subject 2-89-28 Unit 2 Technical Specification Shut Down 12/06/89 Due to Inoperable Standby Gas Treatment 11/08/89 System i
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2 2-89-25 Unit 2 Inoperable Automatic 11/02/89 Depressurization System Due to Non-i 10/07/89 Qualified Components
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3-89-03 Unit 3 Containment Control System Piping
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10/06/89 Outside Design Basis 08/08/89 2-89-29 Unit 2 Primary Containment Isolation
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12/18/89 System Actuation Due to Spiking 11/17/89 Radiation Monitor During Surveillance
2-89-24 Unit 2 Reactor Scram While in Hot Shut-11/06/89 down Due to Local Power Range Monitor 10/06/89 Spiking Upscale 2-89-22 Unit 2 High Pressure Coolant Injection 11/02/89 System Stop Valve Inoperable Due to 10/03/89 Unterminated Electrical Lead 2-89-20 Unit 2 and Unit 3 4 KV Electrical Motor 10/10/89 Leads Not Environmentally Qualified 09/15/89 2-89-30 Unit 2 Shutdown Due to Leaking RCIC 12/26/89 Check Valve 11/26/89 During review of LER 2-89-30, the inspector questioned t.he description concerning event analysis and cause. The LER stated that primary contain-ment as defined in the Technical Specifications was not violated since feedwater check valve 28B and valve MO-29B, which were inside primary containment, were operable.
However, the inspector pointed out that M0-29B does not receive a 10 CFR 50 Appendix J Type C leak test, and therefore,
credit for primary containment integrity cannot be based on MO-298. This valve only receives a remote position indication test every two years in accordance with the Inservice Test Program.
In addition, the inspector pointed out that the description of the root cause was unclear.
The licensee agreed and stated that a revision to the LER would be submitted.
No additional problems were identified during the review.
10.0 Allegation Follow-up The NRC received a series of allegations from contractor Quality Control Inspectors (QCI) regarding the adequacy of Quality Control (QC) verifica-tion of work activities at Peach Bottom. These were transmitted to Philadelphia Electric Company in a letter dated September 27, 1989 (letter
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from W. R. Butler, NRC, to C. A. McNeill, Philadelphia Electric Company).
The licensee responded in a letter dated October 30, 1989 (letter from D.
M. Smith, Philadelphia Electric Company, to NRC).
The allegations centered around specific portions of Modification 2106, implemented on Unit 3 during the recently completed outage.
Modification 2106 involved the replacement of portions of the Emergency Service Water (ESW) system piping. The licensee's written response to the concerns was reviewed by the inspector.
In addition, a sampling review of QC inspection documentation associated with Modification 2106 was conducted.
The review was primarily focused on the associated instrumentation tubing work packages; the alleger's area of concern. The concerns, as trans-mitted to the licensee were reviewed individually and are addressed below.
Item A The alleger stated that he was requested to do a final QC inspection prior to the disposition of relevant Nonconformance Reports (NCRs) and
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Engineering Review Request Forms (ERRFs).
This was raised to two levels of supervision; however, the response reflected only a scheduler need to complete the modification, and was not responsive to the concern.
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There were 28 instrumentation work packages associated with the tubing portion of the modification. The inspector reviewed 3 of the packages to assess the adequacy of QC verification of work activities. Each package consisted of QC inspection documents including tubing and valve installa-tion reports, hanger installation forms and concrete expansion bolt forms.
At the time of the inspector's review the tubing work packages contained only the QC inspection reports. The licensee stated that the work packages used for actual in-field QC verification also contained associated NCRs and ERRFs, and were downsized following completion of the inspections.
The inspector verified that the NCRs and ERRFs referenced in the installation reports had received engineering approval prior to the final QC acceptance date noted in the installation reports.
Verification that all applicable NCRs and ERRFs were referenced in the installation reports was outside the scope of the inspection.
The inspector found no indica-tion that final QC acceptance of work activities was made without having dispositioned all associated NCRs and ERRFs.
Item B The alleger stated that a final QC inspection was requested for a portion of tubing which was found to be incomplete.
The installation was later completed.
Inspector discussions with QC personnel indicated that there were occasions when QCIs were asked to do inspections and found that the installation work was not complete.
The QCIs were directed to perform partial inspections of the completed work, and to keep
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the work package open to allow inspection of the remaining portion.
The inspector noted that the final QC acceptance signature for some packages was dated weeks after portions of the QC verification inspections were performed.
The licensee procedure used for QC verification inspections is CD 5.2, Revision 5, " Procedure for Installation of Piping Systems at Peach Bottom." Review of the procedure indicated no prohibitions on the perfor-mance of QC verification inspections on partially installed hardware.
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The inspector reviewed the tubing installation packages for Differential Pressure Indicators (Dp!) 9729C, DPI 97288, and DPI 9728D to assess the completeness of documented QC inspection activities. This review identi-fied that the listing of tubing components was incomplete.
For example, the installation report for DPI 9729C did not list tubing union tees, making it unclear if the installation was complete at the time of the
inspection.
In addition, review of the completed valve installation
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reports associated with DPI 9729C, DPI 97288, and OPI 9728C indicated that the valve serial numbers, year of manufacture, and the name of the valve manufacturer were not recorded.
The inspector noted that this requirement was included in the body of the procedure, but not on the valve installa-tion report form itself. These installation reports had received final QC acceptance.
Procedure CD 5.2 requires the recording of all heat numbers or identification marks for Q-listed items on the tubing installation report, and the recording of valve data on the valve installation report.
Failure to properly document QC inspection as required by licensee pro-cedures is an apparent violation.
The licensee performed a modifications program audit in December, 1988 which identified a number of concerns regarding QC performance, particu-
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larly in the area of documentation.
Several Corrective Action Requests (CAR) were initiated to track resolution of the concerns.
In response to this the licensee initiated a pilot QC inspection and documentation program in June, 1989. A surveillance conducted by QA in October 1989
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indicated that while improvement had been made, weaknesses remained. The
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licensee plans to formally implement the improved QC inspection and documentation process before implementation of the next signifi. ant modification.
The licensee produced documentation compiled as part of the QC pilot program, supporting the position that the installation had been complete at the time of the inspection for the two instances described above.
In both cases the QC inspections were adequate, however the associated docu-mentation was deficient in that it was not in accordance with applicable procedures. The inspector noted that the missing information was not needed to ensure material traceability. As additional assurance the licensee performed a field walkdown and reinspection of a'il 28 installa-tion packages. While the licensee had not identified the specific docu-mentation deficiencies noted, it was clear that the generic problem was recognized and that substantial corrective actions were being implemented.
Based on this, and the minor safety significance of the examples noted, the licensee's failure to document QC inspections in accordance with
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applicable procedures is considered a noncited violation (NCV 278/89-26-05).
The licensee stated that a supplemental response to the September 27, 1989, NRC letter will be submitted by January 31, 1990.
This NCV will remain open pending review of this supplemental response.
Item C The alleger stated that CAR PC 89027412 was initiated on July 5,1989, to document his concerns.
However, the CAR was voided on July 7,1989.
CAR PC 89027412 was issued on July 6,1989 and dealt with discrepancies in a modification docuent package used in the field by installation workers.
The discrepancies included the lack of controlled ERRFs and approved NCRs, a reference to an irrelevant NCR, and a valve installation report which lacked the approval signature of the installation engineer.
The CAR was voided by an internal quality assurance memorandum dated July 14, 1989.
Review of this memorandum indicated that it did not completely address the specific discrepancies noted in the CAR.
For instance, the memorandum did not address whether the lack of controlled copies of the particular ERRFs noted in the CAR or the lack of engineering approvn1 of the cited NCRs constituted conditions adverse to quality, for which a CAR would be needed. The memorandum implied that the problem was limited to Modification 2106 and thus was not programmatic in nature.
Based on a review of procedure NQA 25, Revision 1, titled " Corrective Action," the inspector noted that a conclusion regarding the non programmatic nature of the problem would provide a potential basis for directing that no action to prevent recurrence was required, but did not provide a basis for voiding the CAR. The memorandum stated that Modification 2106 was the subject of another CAR. That CAR, however, did not directly relate to the field documentation control problems described in CAR PC 89027412.
The inspector concluded that the July 14, 1989, memorandum did not appear to provide adequate justification for voiding the CAR.
This item will remain unresolved pending additional review by the licensee (UNR 278/89-26-06).
Item 0 The alleger stated that contrary to procedural requirements, Modification 2106 instrumentation documentation packages were under the control of the QCI within the plant for periods of several days or more.
Licensee nrocedure CPPB-1, " Procedure for the Control of Field Work Packages,i' Revision ll, specified that all sections of the field work
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package be returned to the document control center (DCC) by the end of each day.
Based on discussions with installation and QC personnel, it appears that portions of the package for Modification 2106 were controlled in a " satellite" document control center, rather than being returned to the DCC daily. The satellite center was established with the assigned installation engineer and site lead man.
CPPB-1 does not include nor does it prohibit the establishment of a satellite center.
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It also appeared that portions of the documentation were outside the central and satellite document centers and were kept for a period of days by QCIs at their work location. At the time of the inspection however, these packages were no longer at the QC work locations.
There was no clear indication of whether the subject documentation was part of a field work package.
In addition, review of logs and records provided no indi-
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cation of the content of the documentation packages or of the time frame this documentation was kept outside the central and satellite document centers.
Finally it appeared that portions of the completed field work packages were kept in the quality assurance conference room and were not returned to the DCC at the end of each day.
It is unclear, however, whether the guidance contained in CPPB-1 applied to field work packages for which installation and QC inspections had been completed.
Licensee management indicated that the need to return the packages daily to the DCC was guidance and not a requirement. The practice was established to ensure that work packages would not be misplaced, requiring generation of replacement packages. Other measures are available to ensure that
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drawing and procedure revisions are incorporated into the packages in a i
timely manner. There appears no safety problem was created by the handling of the packages. The licensee committed to revise CPPB-1 to clarify its intent and application. The inspector identified no additional concerns in this area.
Item E The alleger stated that the internal defects / conditions inspection point for valve installation reports associated with Modification 2106 was marked as N/A.
The alleger believed that this constituted bypassing of a QC hold point.
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Based on discussions with QC personnel, the inspector understood that the valves installed by Modification 2106 were either new valves or had been refurbished under maintenance work controls.
As discussed in its October 30, 1989 response, the licensee determined that an internal defects and condition inspection was not required for new valves frr which appropriate internal inspections would have been performed as part of the manufac-turer's quality assurance program, or for refurbished valves for which internal inspections were performed during the refurbishment process.
In the review of three instrumentation tubing packages for DPI 9729C, DPI 9728B, and DPI 97280, the inspector noted that the internal defect and condition item was marked as not applicable on the valve installation
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reports. An explanatory footnote on these referenced an internal quality assurance memorandum which instructed the QCIs to mark this item as being not applicable.
Engineering documentation for the instrument tubing packages indicated that the valves installed were new valves.
The inspector concluded that the licensee had taken appropriate actions to l
address this issue.
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The alleger stated that accumulators installed in the drywell under Modification 1660 had no documented clean checks. The QCI was asked to sign off that these clean checks had been done.
Ti.e inspector found that the licensee had issued NCR P89-693-412 on August 14, 1989, to address this item.
The NCR received engineering approval on the same date, and quality assurance review and closure on September 19, 1989. The corrective action was to perform boroscopic examination of the accumulators.
The NCR noted that the required clean checks had probably been completed during installation; however, documentation of the clean checks could not be located. The inspector concluded that the licensee had taken appropriate actions to address this issue.
Item G The alleger stated that holes drilled for installation of Modification 2106 instrument tubing supports in residual heat removal rooms "A", "B",
"C", and "D" were drilled deeper than the specified 2 inch depth.
The_ inspector found that the licensee had initiated NCR P89-594-322 on July 11, 1989, to address this issn.
Engineering approved a use-as-is disposition on July 19, 1989, and pality assurance approved closure on August 3, 1989.
The engineering approval for the NCR was based on the conclusion that drilling the holes did not adversely affect embedded rebar, conduit, or grounding cables. Discussions with engineering personnel indicated that drilling clearances had previously been issued for the same wall location to depths of 6 and 9 inches.
The inspector concluded that the licensee had taken appropriate actions to address this issue.
Items H and I During inspection of Modification 2106 instrumentation tubing in the "D" RHR room, the QCI was allegedly directed by the Mechanical Site Lead Man, in a fashion that reflected conflict and potentially an attempt to intimidate the QCI, to continue inspections.
The alleger related three additional instances in which the response from the Site Lead Man appeared intimidating.
In their October 30, 1989 response, the licensee stated that the above incidents were reported to QC management. Discussions with installation management led to counseling of the Site Lead Man. The inspector discussed the incidents with QC and installation management and verified that actions were taken to determine the extent of the problem and to monitor
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the situation. The inspector also held discussions with the involved Site Lead Man.
The inspector determined that documentation on the alleged
incidents, although indicative of less than the desired working relation-ships, did not provide a clear basis for concluding that an intentional
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attempt to intimidate had been involved.
In addition, it appeared that licensee management took action to address this issue once the incidents were made known to them.
Summary The program previously in place for implementation of QC inspections and documentation of these inspections appears to have been weak. This problem was recognized by the licensee in 1988, prior to receipt of the subject allegation.
Substantial action has been taken to improve the process, including reorganization to separate the QC inspection staff from the construction organization, and trial implementation of a strengthened inspection documentation program.
The licensee plans to finalize the documentation enhancements and formally implement the revised program during the second quarter of 1990. As noted above, one noncited violation (NCV) and one unresolved item were identified during the inspection. The licensee has committed to submit a revised response to the NRC by January 31, 1990. The issues associated with the NCV, the unresolved item and review of the licensee's supplemental response will be reexamined during a future inspection. The inspector considers the remainder of the issues discussed above to be resolved.
11.0 Previous Inspection Item Update (Closed) Open Item 50-277/88-200-01 and 50-277/88-200-01 During a team inspection of the licensce's Emergency Operating Procedures (EOPs), the team noted that the Plant Specific Technical Guidelines (PSTGs) were developed following implementation of E0Ps based on Revision 3 of the Emergency Procedure Guidelines (EPGs).
The team further noted
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that, although these PSTGs documented differences to the generic EPGs, they did not appear to be a useful development tool.
The licensee was requested to respond to this issue addressing the planned use of PSTGs in future development of E0Ps at Peach Bottom.
The licensee, in their response dated January 26, 1989, stated that a procedure Generation Package is being developed for converting Revision 4 of EPGs into Transient Response Implementation Plan (lRIP) procedures (Note: E0Ps are a subset of the TRIP procedures at Peach Bottom). The response described a two step process.
First, the EPG step is converted into a PSTG step, then the PSTG step into a TRIP procedure step. Justi-fication of differences and source documents referenced are to be included with each step. All future EPG revisions are to be implemented utilizing the above process.
During this inspection, the inspector reviewed the above process and its implementation, i.e., conversion of Revision 4 of EPGs into the TRIP procedures.
The inspector determined that the conversion is working and progressing well. Based on this determination, this item is closed.
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(Closed) Open Item 50-277/88-200-02 and 50-278/88-200-02 i
As part of inspection 50-277/88-200 and 50-278/88-200, the team became aware that the containment isolation features of the Standby Gas Treatment Systems (SGTS) would intentionally be defeated to allow containment pressure
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reduction before the containment reached its pressure limit. The NRC's
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rationale and goal for containment venting in Revision 2 and 3 of the EPGs, also stated in the recently published safety evaluation of Revision 4 of r
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the EPGs, is to limit containment venting to a "last resort." Considering the importance of this goal, the licensee was asked to reevaluate the use of the SGTS in their E0Ps for control of containment pressure and to submit
a report on this reevaluation.
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The licensee, in their response dated January 26, 1989, submitted a report
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on this reevaluation.
It addressed three distinct pressure regions, followed by a discussion of operation within each region, including pro-
cedures for these operations and other references as listed below:
CONTAINMENT VENTING REGION DESCRIPTION REFERENCES
Containment pressure between atmospheric UFSAR S.2.3.8 and the +2 psig isolation.
Procedures S.3.9.1.C
Containment pressure between the +2 psig UFSAR S.2.3.9 isolation and Primary Containment pressure Tech Spec limit.
3.7.A.6.d Procedure S.17.3.A
Containment pressure at Primary Containment EPG Rev. 3 pressure limit.
PC/P-7 Procedures T-200 through T-2001 The licensee is in the process of revising the above procedures to reflect the changes in Revision 4 of the EPGs.
The revision is expected to be complete by July 1990.
Further, the licensee is also considering a possible modification for the venting under station blackout conditions and related upgrade of the E0Ps by July 1990.
This was a result of a finding from another team inspection (IATI 89-81/81, dated March 1989).
In addition, in response to Generic Letter (GL) 89-16, Installation of Hardened Wetwell
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Vent, the licensee made a commitment in their letter dated October 30, 1989 to implement the required modification (i.e., hardened wetwell vent)
prior to restart following the second refueling outage (Reload 9) at each unit. These outages were then projected to occur in the fall of 1992 for Unit 2 and the fall of 1993 for Unit 3.
The modification will require further changes to the procedures.
Based upon the licensee actions to date this item is closed. Additional review in conjunction with follow-up to GL 89-16 will be conducted during a future inspection.
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12.0 Management Meetings 12.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Plant Manager, Peach Bottom Station at the conclusion of the inspection.
During the inspection, licensee management was periodically notified verbally of the preliminary findings by the Resident Inspectors.
No written inspection material was provided to the licensee during the inspection.
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12.2 November 29, 1990 Management Meeting The licensee's Executive Vice President-Nuclear and members of his staff met with NRC management in Region I to discuss Philadelphia Electric Company's Nuclear Group strategic planning process and 1990 objectives.
In addition, the licensee provided an overview of actions taken in trsponse e
to the results of the most recent SALP reports for Peach Bottom and Limerick Handouts distributed by the licensee during the meeting are included as Attachment II m
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The inspectors discussed issues during the report period with licensee j
staff members at all levels of the organization.
Listed below are the
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primary licensee management personnel contacted.
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D. M. Smith, Vice President, Peach Bottom Atomic Power Station-I._
J. M. Madera, General Manager, Nuclear Quality _ Assurance
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J. F. Franz, Plant Manager, Peach Bottom Atomic Power Station-
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G. F. Daebeler,- Superintendent. Technical
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G. R..Rainey, Superintendent, Maintenance-
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P.' LeQuia, Superintendent Services-j
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J. B. Cotton, Superintendent. Operations a
J. M. Pratt, Manager, Peach Bottom QA
T. E. Cribbe, Regulatory Engineer
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G. A. Bird, Nuclear Security Specialist
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F. W. Polaski, Assistant Superintendent, Operations
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ATTACHMENT II j
Facility and Unit Status i
Unit 2
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November 20-26 100% power.
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November 26 Shutdown initiated due to unisolable leak outside
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l December 2 Mode switch to startup after repair of RCIC leak and turbine hydrogen seal oil leak, c-December 3 Power increase held at 75% for inspection of water box leaks.
December 6 Power increased to 100%.
December 7 Power reduced to 70% for repair of "C" RFP discharge check valve steam leak.
December 10 Power ascension to 100% initiated.
December 15 Reduced power to 65% to test and repair leaks in "C" and "A" water boxes.
December 16 Power ascension to 100% completed.
December 20 Scram due to personnel error during APRM surveillance testing.
December 22 Mode switch to startup.
December 23 Mode switch to run and main generator placed on line.
- December 25 Power increased to 89%.
December 27 Power decreased to 70% to inspect a staam leak on
"C" RFP discharge header, then returned to 85%.
December 28 Power reduced to 70% for repair of steam leak on "C" feedwater discharge header.
December 30 Full power achieved.
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Unit 3
November 20 Mode switch in startup and reactor critical.
November 21 Mode switch to shutdown when EHC pressure regulators i
failed to control reactor pressure.
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November 24 Mode switch to startup and reactor critical.
November 26-29 HPCI, RCIC and MSRV testing at 150 lbs, reactor pressure.
November 30 Reactor pressure decreased from 930 lbs, to 450 lbs.
due to high sulfates.
December 1 Mode switch to shutdown due to low flow of cooling water to CS and RHR motor oil heat exchangers.
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December 5 Mode switch to startup and reactor critical.
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December 7 HPCI and RCIC testing at rated reactor pressure.
December 8 Mode switch to run.
December 9-11 Several unsuccessful attempts to roll the main turbine due to high vibration, low rotor temperature, and low lube oil pressure.
December 11 Successful main turbine roll and subsequent synchronization to the grid.
December 13 Successful completion of main turbine overspeed trip test.
December 13-16 Reactor power increased to 50%.
December 16-20 Several feedwater control perturbations lead to replacement of the feedwater master controller.
December 21
"C" reactor feedwater pump trip due to pump-to-coupling failure at 70% power causing recirculation pump runback and subsequent power decrease.
December 25 High vibration of "B" reactor feedwater pump prompts power reduction from 70% to 43% and subsequent removal of pump from service.
December 28
"B" reactor feedwater pump returned to service and power increased to 70%.
December 29
"A" reactor feedwater pump lube oil problem prompts power reduction to 45% and subsequent removal of pump from service.
December 29
"A" reactor feedwater pump returned to service and power increased to 70%.
December 30-31 Successful completion of recirculation pump trip testing.
December 31 Reactor power at 57%.
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Sponsored and developed
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VISION AREAS TECHNICAL COMPETITIVE POLITICAL CULTURAL Cost of generation in lowest e Nucleer Group well respected
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in a manner which demonstrates our commitment to the heshh and well being of the public and our employees. We encosrage each
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ggfg Quality is everyone's responsibility. All Nuclear Group employees are
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expected to do the job right the first time, stay abreast of technical developments in their area of expertise, and apply new knowledge and
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expertise in a manner which enhances the quality of our operadons.
Nuclen Group Management will support Ngh levels of technical and
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managerial competence through appropriate training and development.
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i Business Focus. We will operate in a cost effecdve, produedve, and efficient BUSINESS. nun W wW pmW& a danmging mk etmment which supports
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i openness to change, a quesdoning attitude, and continual striving for
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FOCUS imp =ve== * *m c=dua ar b*$5 m b=e* c"'==ers/
shucholders, and employees alike.
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TEAMWORK * individuals and deputments in the Nuclear Group
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on our individual and department goals and objectives, we will consider,
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Corporate and Nucleu Group strategies and goals in our decision making.,
We will encourage, listen and respond to employee ideas and suggesdons in
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support of more effective operations.
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PEOPLE '"P'c *c *c 'c' * *""""c " **Pc" ** ***Y ' ** ***d"E W will treat one another in a fair and respectful mannee Individual d!fferences will be explored and dealt with construedvely. Employees and the Company will operate as partners with a mutual commitment to
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excellence. Employees are expected to work in a manner which enhances
Company profitability. In tum, the Company will provide a safe, dynamic, cha!!enging, and mutually supportive work environmen,t, where rewuds me
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directly related to performance.
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INTEGRITY "osidon of public trust. W will continually cam this
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NUCLEAR GROUP STRATEGIC OBJECTIVES
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MANAGEMENT INFORMATION SYSTEM SITE MASTER PLANS CONFIGURATION MANAGEMENT HUMAN RESOURCES l
NUCLEAR ENGINEERING DEPARTMENT PERFORMANCE IMPROVEMENT l
STAFFING REFUELING OUTAGE LENGTH REDUCTION STRATEGIC PLANNING / COST MANAGEMENT
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NUCLEAR GROUP
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STRATEGIC OBJECTIVES FOR 1990
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MANAGEMENT INFORMATION SYSTEM
Design and implement an integrated management j
information system by 1994.
i SITE MASTER PLAN i
Develop and complete implementation of the site master
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plans at both Limerick and Peach Bottom by 1998.
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CONFIGURATION MANAGEMENT
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i Develop and implement by 1995 a configuration
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management program consistent with INPO and industry
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HUMAN RESOURCES
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Develop and implement selection and development systems i
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l Improve the quality of work processes in the Nuclear
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Engineering Department.
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- STAFFING
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I Achieve staffing levels of Nuclear Group Steady State i
Staffing Study by 1992.
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- REFUELING OUTAGE LENGTH
l Achieve 60-day refueling outages on a 2-year operating
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cycle by 1994.
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Implementation of strategic planning and cost management processes which allow us to move our costs to the mean for
comparable plants by 1995.
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Achieve commonality in all functional areas of the Nuclear Group with regard to organization, procedures and training l
by 1995.
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= Increase attention on 1) hot particle
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- Chemistry manual - 1990
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= identify cause of fuel leak and R
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= Resolve outstanding EP audit findings
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- Root cause analysis performed i
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corrective actions
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- Use simulator for drills - 1990
= Continue initiative to further enhance
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- Use of performance indicators
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= Strengthen corporate support of radiological L
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- Formalizing corporate assessment process
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= Assess the engineering program.
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- Improve quality of work processes
- Configuration management program j
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