ML20059G998
| ML20059G998 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 01/20/1994 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20059G974 | List: |
| References | |
| 50-458-93-28, NUDOCS 9401260150 | |
| Download: ML20059G998 (22) | |
Text
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t APPENDIX A
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Gulf States Utilities Docket:
50-458 5
River Bend Station License:
NPF-47 l
During an NRC inspection conducted on November 7 through December 18, 1993, three violations of NRC requirements were identified.
In accordance with the
" General Statement of Policy and Procedure for NRC Enforcement Actions,"
10 CFR Part 2, Appendix C, the violations are listed below:
A.
Criterion XVI, 10 CFR Part 50, Appendix B, requires, in part, that corrective action shall be taken to prevent recurrence of significant l'
conditions adverse to quality.
On June 30, 1993, the licensee inadvertently placed the. plant in a condition prohibited by Technical Specification 3.5.1. which requires i
all three divisions of the emergency core cooling system to be. operable when the plant is in Operational Condition 1, and has no action i
statement that allows the high pressure core spray to be inoperable with either of the other two emergency core cooling system divisions being inoperable at the same time. This is a significant condition adverse to quality and dictates that action a taken within I hour to shut down the
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plant under the provisions of Technical Specification 3.0.3 Contrary to the above, the licensee failed to implement effective measures to prevent recurrence of the June 30 event and on November 4
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while the plant was in Operational Condition 1, Residual Heat Removal l
Pump B was declared inoperable while high' pressure core spray was r
This is a Severity Level IV violation.
(458/93028-2) (Supplement I)
I B.
Technical Specification 6.8.1 requires, in part, that written procedures i
shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
Regulatory Guide 1.33, Appendix A, states that maintenance that can e
affect.the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.
Contrary to the above, maintenance that affected the performance of safety-related equipment was not performed in accordance with written.
procedures, in that:
1.
On November 22, 1993, the instructions for the work performed in accordance with Maintenance Work Order R137896 required that the foreman check and initial each individual's training matrix. The foreman who signed this sheet did not initial any of the individuals training matrix.
I 9401260150 940120 PDR ADOCK 05000458 G
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On December 3, 1993, Step 7 of Maintenance Work Order R137897.
required an inspection of the motor pinion and key of Valve E22*MOVF012 for proper "as-found" installation, using-Corrective Maintenance Procedure CMP-1253, "Limitorque Motor Operated Valves," Revision 9, and the vendor technical manual which required that the key be secured in position by staking the end of the motor shaft keyway. The inspection step was completed and signed off as " satisfactory," when-in fact the key was not secured in position by staking the end of the motor shaft keyway.
This is a Severity Level IV violation.
(458/93028-3) (Supplement I).
C.
Technical Specification 6 8.1 requires, in part, that written procedures shall be established, implemented, and maintained covering the i
applicable procedures recommended in Appendix A of Regulatory i
Guide 1.33, Revision 2, February 1978.
4 Regulatory Guide 1.33, Appendix A, states that maintenance that can affect the performance of safety-related equipment should be' properly.
I preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.
Contrary to the above, on November 17, 1993, while conducting l
troubleshooting activities on the reactor core isolation cooling control circuits in accordance with Maintenance Work Order R178922, the work instructions failed to provide a step that would place the appropriate switch in bypass to prevent a reactor water cleanup system isolation.
As a result, an inadvertent reactor water cleanup system isolation j
occurred.
This is a Severity Level IV violation.
(458/93028-4) (Supplement I).
Pursuant to the provisions of 10 CFR 2.201, Gulf States Utilities is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, D.C. 20555 with a copy to the Regional Administrator, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011, and a copy to the NRC Resident Inspector at the facility that is the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should be clearly marked as a " Reply to a Notice of Violation" and should include fo'r i
each violation:
(1) the reason for the violation,'or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and.
the results achieved, (3) the corrective steps that will be taken to avoid-further violations, and (4) the date when full compliance will be achieved.
If an adequate reply is not received within the time specified in this' Notice, l
an order or a Demand for Information may be issued to show cause why the license should not be modified, suspended, or revoked, or why such other f
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i action as may be proper should not be taken. Where good cause is shown, con.ideration will be given to extending the response time, i
Dated at Arlington, Texas, thisyg day of,sguB.A )994
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1 PLANT STATUS At the beginning of this inspection period, the plant was operating at i
100 percent power.
On November 7, 1993, power was reduced to 62 percent when Reactor Recirculation Pump B tripped.
Power was maintained at 62 percent with the plant in single loop operation until November 11, when the cause of the trip was corrected.
Power was gradually increased to 100 percent by November 17.
The plant continued to operate at 100 percent power through the end of this inspection period.
l 2 ONSITE RESPONSE TO EVENTS (93702)
I 2.1 Reactor Recirculation Pump Trip t
On November 7, 1993, with the reactor operating at 100 percent power, Reactor Recirculation Pump B tripped. As a result of the decrease in core flow to
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approximately one-half of rated flow, reactor power decreased to approximately 65 percent. The operators responded by entering Abnormal Operating Procedure A0P-0024, " Core Thermal Hydraulic Instability," Revision 6, which j
specified the immediate and subsequent operator actions. The operators determined that with the reduced core flow of 41 million pounds per hour and reactor power at 65 percent, there was no need to scram the reactor. The plant was not in the prohibited region of the power to flow chart of Procedure A0P-0024 and Technical Specification 3.4.1.
The operators also monitored the average power range monitors as required by the procedure to ensure that no thermal-hydraulic instabilities existed, and the results were
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entered into the reactor operator's log.
No instabilities were identified.
During the transient, reactor water level increased from 35.8 inches to 41.4 inches, annunciating a high level alarm.
Leve.1 was subsequently restored by the feedwater regulating valves. Because of the feedwater transient, feedwater heater levels fluctuated, and Heater Drain Pump A tripped.
The operators entered the appropriate abnormal operating procedure and restored the pump to service. All other systems responded normally.
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The plant was stabilized at approximately 62 percent power, in single loop operation and in compliance with the action statements of Technical I
Specification 3.4.1.
The recirculation pump trip was preceded by hydraulic power unit trips in Subloops 1 and 2 for Flow Control Valve Based on the alarms received, the B
licensee concluded that the cause of the event was a loss of power (blown fuses) to the Foxboro instrument nest. This nest contained the instrument which compared reactor steam dome saturation temperature with the recirculation pump suction temperature, to ensure that there was sufficient
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- net positive suction head (NPSH) at the pump. When the indicated difference becomes less than 8 degrees, the recirculation pumps are designed to shift to slow speed.
Loss of power to the instrument simulated a loss of adequate NPSH, but instead of downshifting, the pump stopped. After troubleshooting the pump controls, the licensee realized that a downshift would only occur if both pumps received a low NPSH signal, because there was a set of interlocking contacts in the pump controls that prevented one pump from downshifting to slow while the other was running in fast.
After consideration of the possible impact on the plant in single loop operation, the licensee's troubleshooting determined that the loss of power was caused by random failure of a Zener diode in the power supply card in the 3
Foxboro instrument nest. The failed diode caused the fuses to blow, thus protecting the circuits from further damage. The card was replaced and power was restored to the instrument nest.
On November 11, the inspectors observed the operators returning the plant to i
two loop operation.
This was a well-briefed, carefully controlled evolution.
The Operators first rehearsed the operation on the plant simulator to gain experience on the expected plant response.
Flow Control Valve B was closed to the minimum position, and Flow Control Valve A was closed just above the feedwater flow that would automatically down shift the running pump.
l Recirculation Pump B was started in fast speed without incident, and' recirculation flow was balanced by the reactor operator.
2.2 Inadvertent Isolation of Reactor Core Isolation Coolina (RCIC) 1 On November 17, 1993, while performing Surveillance Test o
Procedure STP-207-4501, "NSSSS/RWCU/RCIC Isolation-Main Steaa Line Tunnel Ambient Temperatere High Monthly Channel Functional," Revision 3, a Division I RCIC isolation (,ccurred, closing RCIC Steam Supply Valve E51*MOVF064. At the time, RCIC was required to be operable, because the plant was operating at full power.
The isolation occurred during the restoration portion of the test, when the isolation logic bypass Switch E31A-52A was positioned from " bypass" to
" normal." All indications were normal and no other trips were indicated.
The shift supervisor declared the system inoperable until the cause of the actuation could be determined and corrected. The operators entered the action statement for Technical Specification 3.7.3, which allowed continued plant operation for up to 14 days provided high pressure core spray was operable.
The licensee's investigation and troubleshooting could not immediately l
determine the cause of the. isolation, since the isolation could not be recreated.
However, this isolation was unique, compared with the previous three isolations reported in Licensee Event Reports (LERs) 458/92-029, 458/93-018, and 458/93-022. The isolation of November 17 occurred after the surveillance test procedural steps were completed and final restoration was in
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This enabled the licensee to isolate the cause around possible failures of Relays E31A*K2A, E31A*K25A, and E51A*K100. Actions taken to help identify the cause of recurring previous isolations had already been completed prior to restoration.
These actions included lifting certain leads while the j
test was in progress, and measuring selected _ voltages.
The three relays were replaced (see Section 4.2 of this inspection report) and the surveillance test was repeated satisfactorily. The original relays were tested in the shop, and it was found that on Relay E31A*K2A, Contact M1-T1 was erratic. The contact sometimes failed to close, delayed opening, and had varying contact resistance. However, this relay was not specifically tested by the surveillance, and therefore should not have caused the actuation.
Relay E31A*K25A was tested during the surveillance, but did-not exhibit _any anomalies in the shop.
Both relays were Agastat Model FGP relays, and were' manufactured and installed at approximately the same date. The licensee concluded that Relay E31A*K25A could have spuriously failed, causing the isol ation.
The relays were shipped to Amerace Corporation, the manufacturer, for-failure analysis, to determine causal factors, and to obtain recommended action to prevent similar future failures.
The licensee committed to update the LER reporting this isolation accordingly.
2.3 Substituting Manual Action for Automatic Safety-Related Functions 2.3.1 Division 11 Diesel Generator (DG) Fuel Transfer Pump Failure On November 23, 1993, a trip unit that controlled day tank level and automatic t
cycling of the fuel oil transfer pump on the Division 11 DG failed.
The shift supervisor declared the system inoperable until the cause of the i
failure could be determined and corrected. At 9:11 p.m., the operators entered the action statement for Technical Specification 3.8.1.1, which-requires the verification of all systems, subsystems, trains, components, and devices that depend on the remaining operable DG as a source of emergency power are also operable; otherwise, be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. At this time Division I standby gas treatment system was in a scheduled outage, and this was a system that depended on the operable DG for emergency power.
At 5:07 a.m., the operators exited the 12-hour Technical Specification action statement by replacing the automatic features of the diesel fuel oil transfer pump' with manual action by stationing an operator at the control panel for the DG on a full time basis. Generic Letter 91-18, "Information to Licensee Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability"; and its attachment, Inspection Manual Section 9900, " Operable / Operability:
Ensuring the functional Capability of a System or Component," Section 6.7, provides guidance on substitution of manual action for automatic action. This guidance indicated i
that the substitution of manual actions for automatic action could be
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t accepted, provided the licensee's determination of operability with regard to the use of manual action is focused on the physical differences between automatic and manual action, and on the ability of the manual action to accomplish the specified function.
t The operability determination was based on an operator stationed at the local diesel control panel, and trained to start the fuel oil transfer pump when the DG started.
It was determined that subsequent to that action, the transfer pump could be left running continuously. The overflow line was sized such that all the excess flow would be diverted back to the fuel oil storage tank.
The inspectors questioned the operator stationed at the DG control panel, and found that the operator was trained on the required actions for starting the fuel oil transfer pump. The inspectors noted t;.4t the operator did not have a l
copy of the procedure in his possession containing the steps that had to be performed. The control room responded by immediately sending a copy of t
Station Operating Procedure SOP-0053, " Standby DG and Auxiliaries" with a change notice (CN) for the mcnual actur. tion of the fuel oil transfer pump.
During the inspectors' review of this procedure, it was noted that the procedure was released with the CN incorporated at 8:55 a.m.
Further questioning about'which procedure the operators were using before the CN.was completed revealed that the operator, the control operating foreman, and the shift supervisor could not readily identify which procedure was to be used in performing the required action prior to issuance of the CN.
The guidance in Generic Letter 91-18 required the licensee to have written l
procedures in place and training accomplished on those procedures before substitution of manual action for the loss of an automatic action.
The licensee had not issued guidance procedures or instructions to implement the provisions of the generic letter. The licensee chose instead to.use the guidance in Chapter 9900 of the NRC Inspection Manual. The new operating crew, that came on shift at 6 a.m., was apparently unaware of which procedure i
they would use in starting the fuel oil transfer pump until the CN to Procedure STP-0053 was issued.
2.3.2 Operability of Radiation Monitor RMS*RE21A On December 1, 1993, at 4:11 p.m., the control room annunciator for the Division I containment purge isolation radiation monitor alarmed.
The plant,
was operating at full power, but containment purging was not in progress. The operators followed the alarm response procedure, verified the outboard purge containment isolation valves closed, and determined that the alarm was invalid. At the time, containment pressure was 0.15 pounds per square inch gage (psig).
The operators declared the radiation monitor inoperable, and entered Technical Specification 3.3.2, Action Statement b, at 5:11 p.m.
A priority maintenance work order was issued, and troubleshooting revealed a power supply failure in the radiation monitor.
. At 10:30 p.m., containment pressure reached the maximum allowable value of 1
0.30 psig. Technical Specification 3.6.1.7 requires primary containment pressure to be maintained between -0.3 and +0.3 psig. When outside of these limits, containment pressure must be restored within 1-hour or the plant'must be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and in cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
In order to reduce pressure, containment purge valve needed to be opened; however, the valve was required to be closed to
'i satisfy Action Statement b of Technical Specification 3.3.2.
i For the first few hours after the radiation monitor-failed, the licensee stated that they presumed that repairs would be completed before the -
containment pressure limit would be exceeded.
As time passed, the operators consulted with plant management and licensing.
Enforcement discretion was discussed, along with utilizing the guidance in Generic Letter 91-18.
Because the guidance appeared to be applicable, coupled with the time restraints imposed by Technical Specification 3.6.1.7, the licensee dispatched a radiation protection technician locally at the Radiation Monitor RMS*RE21A detector with a portable radiation monitor and communications to the control i
i room. The control room operators were instructed to isolate the purge path when notified by the radiation protection technician that any significant l
increase in radiation level was measured. The portable radiation monitor used was a Teletector Model 6112B meter, set on the 0-50 milliroentgen per hour scale. The operators informed the inspectors that the safety function of Radiation Monitor RMS*RE21A was being met by manual action and therefore was operable.
By 11:25 p.m., containment pressure was reduced by the normal purge path, satisfying the action statement of Technical Specification 3.6.1.7.
By 4:46 a.m. on December 2, Radiation Monitor RMS*RE21A was repaired, i
functionally tested, and returned to service. The operators exited Action i
Statement o of Technical Specification 3.3.2.
The licensee's actions appeared to be appropriate because (1) Division II was operable and would automatically isolate containment purge when called upon, and (2) Radiation Monitors RMS*RE21A and B setpoints were 1.3 Roentgens per j
hour. The manual action was to occur at any significant increase in the 1
0-50 milliroentgen per hour range, providing a large margin for time response.
The inspector reviewed the actions taken be the licensee and found:
The automatic isolation of the containment purge line on a high radiation signal was a feature designed to mitigate the consequences of an accident.
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When the operator declared RMS*RE21A operable,- based on manual detection and manual actuation, there was no documentation available showing that i
credit for manual isolation to mitigate the consequences of design basis 4
accidents had been established as part of the licensing review of the plant.
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, l The operator's log did not indicate the decision to declare RMS*RE21A
. operable, based on manual detection and manual actuation, nor the exiting of Action Statement b of Technical Specification 3.3.2, which was required in order to permit opening the outboard purge outlet valve t
for containment pressure reduction.
i In lieu of having written procedures in place, as recommended by the guidance of the generic letter, the operators entered the actions in the log. When the inspectors questioned the substitution of log entries for procedures, the licensee stated that this was discussed as an acceptable l
alternative at the February 1993 NRC Workshop on Operability held at.
Arlington, Texas. The inspectors were unable to locate NRC documentation that supported the acceptability of such an alternative.
The licensee's actions to utilize the guidance provided by Generic Letter 91-18 may have exceeded the intent of the guidance, particularly in terms of substituting manual actions for automatic actions were considered for those actions that mitigate the consequences of an accident. This issue will
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require further review to determine whether a Technical Specification violation occurred. This is an Unresolved Item (458/93028-1) pending further discussions between NRC Region IV and NRR as to the appropriateness of these manual actions.
5 2.3.3 Troubleshooting Rod Control and Information System (RC&lS)
On November 14, 1993, the annunciator for RC&IS inoperable was received in the
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control room. Maintenance Work Order (MWO) R155844 was initiated to troubleshoot and repair the RC&IS, but the alarm cleared. before the maintenance activity could be started. The alarm continued to intermittently annunciate, but would not remain in the alarmed state to permit sufficient i
time to adequately troubleshoot the problem.
Eventually, troubleshooting i
successfully isolated the problem to a cable connector in containment penetration Cabinet RCP*TCR09A. The planning for the maintenance to repair i
this problem revealed that it would be necessary to make the alarm functions for control rod drive unit accumulator low pressure and high water level in one quadrant of the RC&IS inoperable.
The licensee performed an operability determination on the control rod drive i
accumulators with the low pressure and high pressure alarms inoperable, and concluded that the accumulators were operable. This conclusion was based on the planned manual compensatory actions. These actions were to verify accumulator pressure was greater than or equal to 1520 psig at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and to verify accumulator water was drained at least once per 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. These time intervals were based on existing Technical Specifications at Grand Gulf Nuclear Station.
The inspectors reviewed the licensee's actions against the guidelines listed in Generic Letter 91-18 and found the licensee's actions to be appropriate.
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The failed cable connector was replaced, and the RC&IS system was satisfactorily tested and declared operable.
2.4 Failure to Comply with Technical Specifications i
On November 4, 1993, the High Pressure Core Spray (HPCS) system was in an inoperable status during signature testing on the service water supply valve to the HPCS pump room unit cooler. While the HPCS system was-l inoperable, the "B" train of the Residual Heat Removal (RHR) system was rendered inoperable during the performance of Surveillance Test
'l Procedure STP-204-6304, " Loop B RHR Valve Operability Test," Revision 7.
Having HPCS and RHR B both inoperable is not specifically addressed by Technical Specification 3.5.1, and thus required entry into Technical 1
Specification 3.0.3.
The first step of the surveillance procedure was to close E12*MOVF004B, which i
isolated the suction to the RHR B pump, rendering the entire RHR 8 loop l
inoperable. The operators realized they were in a condition prohibited by the Technical Specifications as soon as the switch was positioned to close the valve. The plant was only in this condition for the period.of time the valve
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took to fully cycle close, then re-open (approximately.2 minutes).
Immediate corrective actions included restoring the RHR B to an operable status by reopening the valve that rendered the system inoperable. All j
individuals involved in this event were counseled on the significance, and the 1
possible consequences, of an event of this type. A Condition Report was written to enter this problem into the licensee's corrective action program.
lne licensee assembled a "high performance team" to determine the root cause of the event, any other contributing factors, and the corrective actions needed to prevent this type of event from reoccurring.
The team determined the root cause to be a series of human errors, but failed to identify any specific corrective actions that would prevent recurrence. The licensee stated that the processes in place to identify and track plant conditions were adequate. Consequently, the human error aspect was addressed, because human errors appeared to be defeating the process.
At the end of this inspection period, which was over a month after the November 4 event, the licensee's operations management removed one operator from performing licensed activities and redistributed senior reactor operators to provide a better balance of strengths within certain watch sections. The licensee has been focusing on human performance, self-checking, and accountability of corrective actions to reduce personnel errors.
i A similar event occurred on June 30 when the HPCS and RHR A were both decla' 1 inoperable for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 44 minutes. During that time frame the plant was operated in noncompliance with Technical Specification 3.5.1, because there was no associated action statement for that condition.
The lir.ensee failed to i
recognize that they were in a Technical Specification 3.0.3 action statement j
with both systems declared inoperable.
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p-i V e The corrective actions that the licensee implemented after the June 30 event may not have been fully effective, because they did not prevent another inadvertent entrance into Technical Specification 3.0.3 involving Emergency Core Cooling Systems (ECCS). The operators should have known which systems were inoperable and what would be the consequences of declaring another ECCS inoperable.
Although this incident was promptly identified by the licensee, it was expected that the licensee's corrective action for the June 30 violation would have prevented the November 4 incident.
In addition, plans to correct this incident were not implemented by the licensee within a reasonable time after the initial event. Therefore, failure to implement prompt and effective corrective action for both the June 30 and November 4 incidents is a violation (458/93028-2) of 10 CFR Part 50, Appendix B, Criterion XVI which requires corrective action to prevent recurrence of significant conditions adverse to quality.
2.5 Conclusions The overall performance of plant staff, during and subsequent to the November 7,1993, reactor recirculation pump trip was good.
Direct' management oversight, and effective teamwork en the part of svorting organizations, was evident.
The licensee's actions to determine and correct the cause of the November 17 RCIC isolation were appropriate to the circumstances.
The licensee's activities demonstrated poor performance in substituting manual for automatic actions on the DG fuel oil transfer pump in accordance with the guidance provided by Generic Letter 91-18.
The licensee's actions to utilize the guidance in Generic Letter 91-18 in substituting a portable radiation monitor in place of an inoperable installed radiation monitor may have exceeded the intent of the guidance. An unresolved item has been identified to track further review of this issue.
The licensee's utilization of the guidance provided by Generic Letter 91-18 in substituting manual actions to monitor control rod drive unit accumulator leakage and pressure was appropriate.
Procedures were in place, personnel were trained, and proper log entries were made.
A violation was identified because of a repeat occurrence where an ECCS was inadvertently rendered inoperable when prohibited by Technical Specifications.
Although adequite programmatic controls appeared to be in place, previous corrective actions to prevent the human errors that defeated the controls did not appear to be fully effective.
. 3 OPERATIONAL SAFETY VERIFICATION (71707)
The objectives of this inspection were to ensure that this facility was being operated safely and in conformance with regulatory requirements, and to ensure that the licensee's management controls were effectively discharging the licensee's responsibilities for continued safe operation.
3.1 Control Rece Observations The inspectors observed operations in the control room during normal and.
backshift hours on i sampling basis. The operators continued to demonstrate formality and professionalism as they executed their duties. Communications were crisp and repeat-backs were often utilized. On several occasions, when complex operations were underway, the operators emphasized keeping distractions to a minimum.
3.2 Plant Tours The inspectors toured various accessible areas of the plant to observe safety-related equipment condition, status, and housekeeping. Overall, most areas of the plant were in good condition; however, some exceptions were noted, and brought to the attention of the shift supervisor or plant management for action.
Examples include, anticontamination clothing receptacles full; tools and hardware left unattended; fire sealing equipment chained to a safety-related, seismic hanger; two ladders unattended and not secured; a ladder being stored in a nondesignated storage area deficiency tags were lying on the floor, and bits of sealant left around a standby gas treatment fan after repairs.
3.3 Security Observations The inspectors observed evening drills conducted during the Operational Safeguards Response Evaluation performed during the week of December 8, 1993.
The results will be published in a safeguards report from NRC Headquarters.
3.4 Radiation Protection Activities On November 19, 1993, the inspectors accompanied a radiation protection technician and a junior technician on routine surveys in the radioactive waste building on the 166 and 120 foot elesations. The technicians followed Radiation Protection Procedure RPP-0006, " Radiological Surveys," Revision 6.
The junior technician obtained the radiation readings and smears, while the senior technician supervised, and pointed out some additional places where smears should have been taken. During the survey on the 166 foot elevation, the technicians utilized an old survey map to verify that radiation postings were in the correct location and that the radiation readings were similar to the data being gathered by the technician. While performing the survey on the 120 foot elevation there was no survey map. The junior technician surveyed
r the area and located a low level source. The smears from the areas were then checked for any possible contamination.
3.5 New 10 CFR Part 20 Trainina The licensee required all plant personnel who enter the radiologically controlled area to attend the new 10 CFR Part 20 training by January 1, 1994.
The inspectors attendeo and evaluated a training session on this topic on December 14, 1993.
In general, the training that was provided was of high quality and covered appropriate topics.
In particular, the training highlighted the differences between the current terminology and those of the new regulations, the posting requirements for all areas within the radiological controlled area, and the differences in the old and new administrative limits and the process for extending these administrative limits.
l The instructor demonstrated a thorough knowledge of the material, and presented the course in a professional and enthusiastic manner.
3.6 Conclusions Operators continued to demonstrate professionalism and formality in the control room.
Log keeping has improved, with a few exceptions.
Housekeeping practices were acceptable in most areas of the plant.
Some exceptions were noted, but were corrected.
The inspectors concluded that the radiation protection technicians performing the radioactive waste building surveys performed well. The surveys were accomplished in accordance with the applicable procedure.
Good techniques wer
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T w.:ctors concluded that the licensee's training for the new It
" / art 20 was excellent. The instructor presented the necessary v
in.ormation on how the regulations have changed and how these changes affect radiatiot workers.
4 MONTHLY MAINTENANCE OBSERVATIONS (62703) i The station maintenance activities addressed below were observed and documentation reviewed to ascertain that the activities were conducted in accordance with the licensee's approved maintenance programs, the Technical Specifications, and NRC Regulations.
l 4.1 Limitoraue Motor Pinion Gears l
On November 22, 1993, the inspectors observed the inspection of the motor i
pinion on Va;ve IDFR*MOV146 and replacement of the motor pinion key. This work was authorized by MWO R137896 as part of the licensee's continuing review i
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i of the condition of safety-related motor-operated valve motor pinions. The key and set screw were found properly installed and locked in place.
The pinion was correctly reinstalled in accordance with the NW0.
7 During the inspectors' review of the completed MWO package, it was found that the foreman who signed the maintenance briefing and training matrix verification sheet failed to ensure that the proper training matrix number was listed by initialling the appropriate blocks, as required by instructions in the MWO.
The inspector also noted one case in which a worker signed his own j
training block.
Procedural controls are required by Technical Specification 6.8.1 for I
maintenance affecting safety-related equipment. The procedures and job plans i
for the work performed required that the foreman check and initial each individual's training matrix. The failure of the foreman to follow the job plan is the first example of a procedural violation (458/93028-3) for failure to follow procedures.
On December 3, the inspectors observed the inspection of the motor pinion installation on high pressure core Spray Miniflow Valve E22*M0VF012.
The work was to be performed in accordance with MWO R137897,_ by a team of individuals consisting of engineers and technicians assigned to system engineering for motor-operated valve work and testing.
1 Step 7 of the work instruction required an inspection of the motor pinion and key for proper "as found" installation, using Corrective Maintenance Procedure CMP-1253, "Limitorque Motor Operated Valves," Revision 9, and the vendor technical manual. When the motor was removed from the operator, the j
inspectors noted that the key had not been secured in position by staking the end of the motor shaft keyway as described in Procedure CMP-1253.
In addition, the key protruded beyond the end of the motor shaft by at least 1/64 inch, indicating further that the key was not properly secured.
The i
pinion set screw was properly locked in place, which in turn might have i
prevented the pinion from slipping off.
The inspectors reviewed the documentation of Step 7, which indicated that the pinion and key were found to be " satisfactory." The step had been signed off as completed.
The inspectors noted the diswepancy and requested an explanation from the i
engineer in charge of the team. He explained that he believed the installation was correct based on the consensus of other team members.
The inspectors found that not all members of the team understood what configuration was required by Procedure CMP-1253.
Step 7 of the MWO also referred to the vendor manual, which clearly indicated that the key be secured in position by staking the end of the motor shaft keyway. However, the vendor manual was not at the job site. After obtaining the manual, the team acknowledged the discrepancy, and Step 7 was corrected to reflect an unsatisfactory "as-found" condition.
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Failure to comply with the requirements of Step 7 of MWO R137897 is the second example of a violation (458/93028-3) for failure to follow procedures.
The licensee counseled the members of the motor-operated valve maintenance team to ensure that procedures were being followed, and to retrain them on the motor pinion configuration requirements.
1 Although the k.ey was not properly locked in place, the licensee did not consider the valve to have been inoperable because the pinion was locked in-place with the set screw.
However, because one pinion was found improperly secured, the licensee indicated plans to inspect all 11 safety-related valves that had motor work since 1987.
The licensee also stated that they were evaluating a method of sampling records on valve motor work performed prior to initial startup. The staking of shaft keys issue had been previously identified as Unresolved Item 458/93026-3.
j 4.2 RCIC Isolation Troubleshootinq
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On November 19, 1993, the inspectors observed the performance of MWO R178922 issued to troubleshoot and repair the cause of the RCIC isolation which 1
occurred on November 17, 1993 (Section 2.2).
The MWO took baseline voltage
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drop readings, inspected relays E31A*K2A and E31A*K25A, and re-performed I
Procedure STP-207-4501 with the old relays in an effort to recreate the actuation condition.
i The operators entered into the appropriate 2-hour Technical Specification action statements when the associated Division I trip units were placed in j
trip. These 2-hour action statements were correctly entered and tracked in the short term action statement log. Also, the technicians used new surveillance tags under General Maintenance Procedure GMP-0042, " Circuit i
Testing and Lifted Leads and Jumpers," Revision 78, which worked well.
I Troubleshooting activities were interrupted three times to revise the procedure:
(1) a recorder was added to the MWO to aid in the troubleshooting; (2) word descriptions in the MWO were changed to be consistent with the process computer; and (3) the control room panel nm,% was not listed in the surveillance procedure for three switches.
All three issues were resolved before the troubleshooting continued.
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The troubleshooting results indicated that: (1) measured voltages did not indicate any unusual voltages; (2) visual inspection of the relays did not l
indicate anything wrong; and (3) the re-performance of Procedure STP-207-4501 did not reproduce the original actuation.
The technicians could not i
immediately determine the cause of the isolation.
Additional work instructions were added to the MWO to replace E31A*K2A, E31A*K25A, and E51A*K100. During post maintenance testing following replacement of the relays, a Reactor Water Cleanup System (RWCS) isolation occurred during the retest on the E51A*K100 relay. A functional test was written into the MWO to test the new relay.
A job step to place the RWCS
. isolation bypass switch in the bypass position was not included in the procedure. The licensee's investigation into the RWCS isolation determined that the job planner did not plan the retest adequately. The planner stopped his research at the E51A*K100 and E12*K3A relays which provided a half main steam isolation valve isolation. The licensee. concluded that if the planner had continued to research further into the drawings and schematics, and followed the circuit to the final contacts, he would have determined that an RWCS isolation would also occur if the bypass switch was not positioned. The failure to provide adequate work instructions on safety-related equipment is a violation (458/93028-4) of Technical Specification 6.8.1.
The inspectors questioned the appropriateness of the licensee's use of MWO instructions for complex postaaintenance tests or partial surveillance tests.
Section 5.3 of this report has another example of similar use of MW0s.
Licensee representatives responded that they would study the matter further and inform the inspectors of the results of their evaluations.
4.3 Conclusions During observation of motor-operated valve motor pinion inspections, two examples of a violation of procedures was identified. One example was administrative in nature, and the second example directly affected the results of the inspection in a nonconservative manner.
The inspectors concluded that poor planning of postmaintenance test instructions resulted in an inadvertent RWCS isolation. A violation was identified for failure to provide adequate procedures affecting safety-related equipment.
5 BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)
The inspectors observed the surveillance testing of safety-related systems and components addressed below to verify that the activities were being performed in accordance with the licensee's approved programs and the Technical Specifications.
5.1 Division I DG Operability Test On December 2, 1993, the inspectors observed the performance of the Division I DG (DG) monthly operability test in accordance with Surveillance Test Procedure STP-309-0201, *DG Division I operability Test," Revision 9A.
Before the surveillance was started, the operators walked through the procedure and noticed that the procedure had two editorial errors that previous operators appeared to have worked around. A CN was issurM to correct these two discrepancies before starting the procedure.
Continuous communications had been established, as required, between the control room and the DG building. The test was performed by two licensed reactor operators with the control operating foreman providing additional
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oversight in the control room.
The operator followed the applicable procedure in a step-by-step manner, and self-checking was evident. The inspectors watched the control room operator as he verified prerequisites completed and then performed a manual start of the DG. The timing test was satisfactorily completed using calibrated stopwatches.
Procedure Step 7.16 required the operator to initiate a " tracking LC0" to perform a 24-hour postrun air roll of the DG. On December 3, the operator performed an air roll of Division II DG instead of the Division I DG. The operators involved believed that the air roll was'to be performed on the Division II DG. The shift technical advisor, the control operating foreman, and the shift supervisor all failed to recognize the error during the evolution.
Once the error was identified, the Division I DG air roll was completed as i
required.
Each air roll was performed separately using the proper procedures and log entries, including entries into the required Technical Specification action statements. No procedures or Technical Specifications were violated; however, this was another human error made by the operators, indicating a need for effective corrective action to place human errors in check.
The inspectors noted that in the control room log the operator simply listed the Division II DG air roll followed by the Division I DG air roll without mentioning that Division II DG air roll was in error.
Furthermore, a i
condition report was not initiated until Operations Management directed that one be written.
Failure to document the error in the log or on a condition report is another example of poor attention to detail and implementation of the licensee's corrective action program.
In this case, operations management oversight corrected the specific problem.
5.2 Calibration of Division I H_ydrogen Analyzer and Monitor On December 6, 1993, the inspectors observed the performance of portions of Surveillance Test Procedure STP-254-4203, " Accident Monitoring - Drywell and Primary Containment Hydrogen Concentration Analyzer and Monitor Quarterly i
Channel Calibration," Revision 11. The inspectors reviewed the procedure and i
determined that it implemented the requirements of Technical Specification 4.3.7.5, and that it was being performed within its required time frame.
The technicians obtained the shift supervisor's permission prior to starting the surveillance, and notified the control room operators of all expected alarms that would be received during the surveillance.
Procedural errors were corrected with a CN as the technicians found minor editorial problems, in~ lieu of the previous practice of working around them.
The technicians followed the t
procedure in a step-by-step manner, and the extra technician verified each step performed. All test equipment used in this surveillance was verified by the inspectors to be currently calibrated.
. 5.3 Logic System Functional Test (LSFT) on 4160 Volt Switchaear On December 11, 1993, the inspectors observed portions of the LSFT performed i
on specific components in the Division 14160 Volt safety-related switchgear in accordance with MW0s R200233 and R200235.
As part of the ongoing corrective action for LSFT overlap deficiencies found in surveillance test procedures (as reported in LER 458/93-002 in March 1993 with subsequent updates in April and June 1993), the licenses's reviews identified test procedures that failed to test certain relay. contacts. These.
contacts were associated with load shedding and sequencing of loads when the Division I or II emergency DG was the source of power to vital busses, following a loss of offsite power (LOP) and a subsequent loss of coolant accident (LOCA).
Failure of this feature to function under these circumstances could result in DG voltage or frequency being degraded by the simultaneous loading from large components responding to the LOCA signal instead of shedding and sequencing loads in the loading profile described in the updated safety analysis report.
l The DGs were not declared inoperable because there was no requirement in the Technical Specifications to surveillance test this feature in order to verify i'
operability.
Technical Specification 4.8.1.1.2 requires load shedding and load sequencing tests with a LOP, a LOCA, and both at the same time, but it l
does not address testing this feature with a LOP and a delayed LOCA, nor a LOCA with a delayed LOP. The licensee stated that they were evaluating whether a change to the Technical Specification would be appropriate.
l Normally, testing of these features have been tested in accordance with surveillance test procedures during the cold shutdown condition of a refueling outage. The licensee decided it would be prudent to test these features in a timely manner, but the published test procedures were complex and not designed for use during power operation. Only the specific contacts and circuits' l
identified were verified functional through troubleshooting techniques, using-MWO 200233 as a test instruction.
7 MWO R200235 addressed checking of a pair of contacts designed to permit using the LOCA override switches to reopen postaccident sampling valves following a LOCA isolation signal. These contacts also were found to not have been tested during the applicable 18-month LSFT, but there were no technical specification i
surveillance requirements applicable to this feature. However, Technical Specification 6.8.4.c requires a program to ensure the capability to obtain 4
and analyze postaccident samples, and therefore the licensee considered it prudent to test these features also.
The inspectors reviewed the MW0s and noted that each received a review by engineering, electrical maintenance supervision, and quality control review.
A briefing was conducted in the control room with the operators and the i
electricians. The evolution was carefully controlled, with good communication between the electricians and the operators.
Leads lifted and fuses removed were controlled in accordance with the licensee's administrative requirements.
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, 1 The work instruction was followed with self-checking evident.
The test was completed with satisfactory results. The inspectors reviewed the completed work package and found no discrepancies.
5.4 Conclusions Conduct of the DG surveillance was performed well until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> later when the wrong DG was selected for the postsurveillance air roll. Operator performance was poor in that the error was made, and the operators did not issue a condition report until challenged by management.
The calibration of the Division I hydrogen analyzer'and monitor was conducted in an excellent manner, with satisfactory results.
1 The licensee's reviews of logic system functional tests for adequacy and appropriateness continued to demonstrate strengths in attention to detail.
Performance of this complex partial surveillance test was observed to be carefully controlled and completed without incident.
6 ONSITE REVIEW OF LERs (92700) 6.1 (Closed) LER 458/92-009: Discrepancy In Technical Specifications led To Failure To Properly Perform Surveillance Tests l
By letter dated March 20, 1993, the licensee reported that leak rate tests had not been performed on a group of containment isolation valves in the post accident sampling system. The licensee stated that other valves not requiring testing were incorrectly listed in the Technical Specifications in place of the valves that should have been tested. When the problem was identified, the proper valves were leak tested with satisfactory results.
i The inspectors verified that the licensee had revised Surveillance Test Procedure STP-610-3827, " Reactor Plant Sampling Valve Leak Rate Test,"
Revision 4, through the issuance of CN 92-0960 on August 31, 1992, to incorporate the correct valves.
The inspectors also verified that License Amendment Change Request 92-11 included a correction to the valve listing in the Technical Specifications.
6.2 (Closed) LER 458/92-022:
Entry Into Technical Specification 3.0.3 Due
.To Failed Charcoal Analysis For Division 1 Control Building Filter Train The licensee reported that both divisions of the control room ventilation system were declared inoperable on October 7,1992. The results of the Division I filter train charcoal analysis was found to be unacceptable, while the Division 11 filter train was out of service for preventive maintenance.
The licensee immediately completed the Division II maintenance activities and-later replaced the Division I charcoal.
The inspectors questioned if the licensee had initiated any provisions to ensure that a similar problem would not occur. The licensee provided a copy-
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- I of Operations Policy 011 dated December 11,-1992, that prohibits preventive maintenance on the opposite division until the result of any outstanding charcoal analysis was received.
i 6.3 (Closed) LER 458/92-024:
Eauipment Problems In The Control Buildinq j
Ventilation System Results in Entry Into Technical Specification 3.0.3 A second situation in which both divisions of the control building ventilation system were declared inoperable occurred on October 18, 1992.
Revision 3 of this report was submitted on March 1, 1993. The report discussed a situation-l where Chiller ID tripped while Chiller IB was undergoing preventive maintenance. The Division I chillers (IA and IC) were inoperable because of an electrical fault in the control panel.
The licensee corrected the fault and returned the Division I chillers to operation and completed the maintenance on Chiller IB to return the Division II chiller system to operation. The licensee later repaired the problem with Chiller ID.
Operations Policy 011 was issued to further ensure that components of opposite trains are not removed from service for preventive maintenance with redundant l
train components out of service.
l 6.4 (Closed) LER 458/92-025: Technical Specification 3.0.3 Entry Due To A i'
Faulty Connection Coincident With Failure Of The Duct Heater For The Control Building Ventilation System A third situation occurred on November 10, 1992, involving the control room ventilation system.
Division 11 Chiller IB circuit breaker tripped on an overcurrent signal while Division II Chiller ID was undergoing preventive maintenance. Division I was inoperable at that time because of a failure of the control room duct heater.
The licensee corrected. the problem with j
Chiller 18 and returned it to service.
Since the problem involved the overcurrent trip device connection, all other similar circuit breakers were
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checked.
No additional problem were found.
The inspectors reviewed Preventive Maintenance Procedure PMP-1021, "G.E. 480V Air Circuit Breakers," Revision 4, and found it acceptable. As above, the j
issuance of Operations Policy 011 was designed to prevent similar problems.
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ATTACHMENT 1 1 PERSONS CONTACTED 1.1 Licensee Personnel
- R. E. Barnes, Supervisor, ASME/ISI
- J. B. Blakely, Director, Predictive Programs
- 0. P. Bulich, Director, Licensing B. R. Burke, Director, Chemistry Supervisor F. N. Carver, Director, Employee Relations C. R. Coats, Electrical Maintenance Supervisor
- R. E. Cole, Process Systems Supervisor D. R. Clymer, Senior Human Performance Engineer W. L. Curran, Cajun Site Representative L. L. Dietrich, Supervisor, Nuclear Licensing R. G. Easlick, Radwaste Supervisor
- E. C. Ewing, Assistant Plant Manager, Maintenance C. L. Fantacci, Radiological Engineering Supervisor J. J. Fisicaro, Manager, Safety Assessment & Quality Verification R. W. Frayer, Procurement Services & Materials A. O. Fredieu, Supervisor, Maintenance Services
- P. E. Freehill, Assistant Plant Manager, Outage Management
- K. D. Garner, Licensing Engineer
- K.
J. Giadrosich, Director, Quality Assurance P. D. Graham, Vice President, Nuclear Integration
- J. R. Hamilton, Manager-Engineering W. C. Hardy, Radiation Protection Supervisor
- H. B. Hutchens, Director, Nuclear Station Security R. T. Kelly, Instrument and Controls Supervisor G. R. Kimmell, General Maintenance Supervisor J. W. Leavines, Supervisor, Nuclear Safety Assessment Group
- T. R. Leonard, Manager-Engineering / System Engineering
- D. N. Lorfing, Supervisor, Nuclear Licensing R. C. Lundholm, Supervisor, Mechanical Process Systems
- 1. M. Malik, Supervisor, Corrective Action & Reviews C. R. Maxson, Supervisor, Performance Assessment Group J. R. McGaha, Vice President, River Bend Nuclear Group J. F. Mead, Supervisor, Control Systems
- W. H. Odell, Director, Radiological Programs
- S. R. Radebaugh, Manager, Modification Construction L. W. Rougeux, Senior Independent Safety Engineering Group Engineer
- J. P. Schippert, Assistant Plant Manager, System Engineering
- M. B. Sellman, Plant Manager B. R. Smith, Mechanical Maintenance Supervisor M. A. Stein, Director, Plant Engineering
- K. E. Suhrke, Manager, Site Support
- R. P. Thurow, Assistant Plant Manager-Continuous Improvement W. J. Trudell, Assistant Operations Supervisor
- J. E. Venable, Assistant Plant Manager, Operations & Radwaste G. S. Young, Supervisor, Reactor Engineering
i Denotes personnel that attended the exit meeting.
In addition to the personnel listed above, the inspectors contacted other personnel during this inspection period.
2 EXIT MEETING An exit meeting was conducted on December 16, 1993.
During this meeting, the inspectors reviewed the scope and findings of the report.
The licensee acknowledged the inspection findings documented in this report.
The licensee did not identify as proprietary any information provided to, or reviewed by the inspectors.
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