IR 05000315/1995010
| ML17333A197 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 10/09/1995 |
| From: | Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17333A198 | List: |
| References | |
| 50-315-95-10, 50-316-95-10, NUDOCS 9511280025 | |
| Download: ML17333A197 (36) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
REPORT NO.
50-315 95010 50-316 95010 FACILITY Donald C.
Cook Nuclear Generating Plant LICENSEE Indiana Michigan Power Company Donald C.
Cook Nuclear Generating Plant 1 Riverside Plaza Columbus, OH 43216 DATES August 18, 1995 through October ll, 1995 INSPECTORS B. L. Bartlett, Senior Resident Inspector D. J. Hartland, Resident Inspector C.
N. Orsini, Resident Inspector J.
Schapker, Reactor Inspector R. A. Paul, Reactor Inspector I. N. Jackiw, Reactor Inspector APPROVED BY W. J.
opp, Chief Reac r Projects Branch
D te AREAS INSPECTED A routine, unannounced inspection of operations, engineering, maintenance, and plant support was performed.
Safety assessment and quality verification activities were routinely evaluated.
Follow-up inspection was performed for non-routine events and certain previously identified items.
95iid80025 95iii3 PDR ADQCK 050003i5
k
Executive Summar OPERATIONS Human performance issues continue to exist in operations that pertained to worker performance and weak management oversight as evident by:
August
September
September
September
A Unit 2 trip resulted from the mis-adjustment of control rod drive motor generator voltages by operations.
The inspectors determined that there was
<<isufficient management oversight, guidance, and information concerning relay chattering (section 1.1.2).
SELF REVEALING A brief loss of all Unit 1 control room annunciators resulted from a personnel error by an operator (section 1. 1.5).
SELF REVEALING Unit 2 tripped due to a mis-operation of the reactor trip breaker handswitch due to an operator error (section 1. 1, 1).
SELF REVEALING Component cooling water flow on Unit 1, was less than required by procedure.
The low flow was the result of poor operator awareness (section 1. 1.4).
INSPECTOR IDENTIFIED September
During routine refueling operations on Unit 1, a fuel assembly was heavily damaged due to personnel error, weak procedures and lack of management oversight (section 1. 1.3).
SELF REVEALING The licensee's corrective actions were good but the licensee's recognition of the pattern of personnel errors was not timely.
When the pattern was recognized, the licensee initiated short anu long teri, corrective actions to address a number of programmatic weaknesses and improvement opportunities.
INSPECTOR IDENTIFIED Initially, the licensee's FHEZ program was determined to be in need of improvement.
After changes were implemented, FHE was observed to improve but was still not strong as items continued to be identified in
,the reactor vessel and inside of the FHE2.
The licensee did however have a good program to search for, identify and remove foreign material.
The inspectors concluded the licensee's actions to recover the loose debris were thorough.
INSPECTOR IDENTIFIED
MAINTENANCE AND SURVEILLANCE Pre-conditioning of the emergency diesel generators prior to surveillance testing.
(unresolved item in section 2.4).
INSPECTOR IDENTIFIED Good corrective action and root cause analysis were noted by the inspectors (section 2.2).
On August 25, 1995, the licensee identified concerns with the environmental qualifications of certain Unit
components.
The licensee appropriately and conservatively expanded the scope of their investigation, shutdown Unit 2 for repairs when the same problems were found to exist there, and corrected the deficiencies.
LICENSEE IDENTIFIED ENGINEERING Poor followup to technical issues including the failure to learn from pre-cursor events.
1.
There was an untimely response to control rod drive motor generator set relay chattering (section 3. 1).
The inspectors concluded that the licensee did not take adequate action in the short term to address the degraded relay condition.
INSPECTOR IDENTIFIED 2.
3.
Root cause evaluations and corrective actions were insufficient to prevent Unit 2 turbine trips due to moisture separator re-heater drain tank high levels (section 3.3).
The trips occurred on December 11, 1994 and August 26, 1995.
INSPECTOR IDENTIFIED On September 19, 1995, a component cooling water valve was identified as stuck open by the licensee.
There were previous opportunities to identify and correct this deficiency that were missed (section 3.4).
INSPECTOR IDENTIFIED On August 18, 1995, the Unit 1 West motor driven auxiliary feedwai, pump tripped on instantaneous overcurrent.
Despite previous failures of the pump motor in the same manner, the licensee failed to perform a sufficiently detailed root cause analysis until questioned by the inspectors (section 3.5).
INSPECTOR IDENTIFIED Improper setting of the torque switches for motor driven auxiliary feedwater valves was caused by a failure to recognize the most limiting condition (section 3.2).
LICENSEE IDENTIFIED
PLANT SUPPORT No concerns were identified in the plant support area.
The inspectors had the following observation:
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Despite an early entry into the Unit 1 outage and an unplanned extension to the outage, radiation exposure remained under budget (section 4. 1).
SAFETY ASSESSMENT AND EQUALITY VERIFICATION Based on the untimely recognition of the pattern of personnel e:
-. ors, the inspectors were concerned thai the self assessment activities in Operations have not been effectively critical of performance, Also, even though the licensee has a low threshold for identifying issues, the.inspectors were concerned that the quality assurance organization had not raised in a'imely manner to the appropriate management the declining trend in human performance.
Summar of G en Items Violations: not identified in this report Unresolved Items: identified in section 2.4, and updated in section 3.2 Ins ector Follow-u Items:
updated in section 1.2. 1.2 Non-cited Violations: identified in section 1. 1.3 and 1. I
INSPECTION DETAILS 1. 0 OPERATIONS NRC Inspection Procedure 71707 was used in the performance of an inspection of ongoing plant operations.
Operator performance continued to be poor with multiple examples of personnel errors identified by the licensee and the inspectors.
1. 1 Human Performance Issues 1. l. 1 Tri on His-0 eration of Reactor Tri Handswitch Unit 2 On September 8,
1995, Unit 2 tripped due to a mis-operation of the reactor trip breaker handswitch.
The mis-operation was due to a personnel error.
All equipment operated as designed and the licensee stabilized the reactor in Node 3.
The trip occurred during restoration from solid state protection system (SSPS)
te.ting.
The reactor trip bypass breaker was locally placed in service and then the main breaker was opened locally.
At the end of testing, the reactor operator was requested to 'close the main breaker using the control room handswitch.
In error, the operator first took the handswitch to the open position, and then went to close the breaker.
Even though the main breaker was already open, taking the handswitch to the open position sent a cross signal to the other train's reactor trip breaker, resulting in the reactor trip.
Prior to this event the NRC had recognized that there was an increased incidence of personnel errors (see inspection report 50-315/316-95009).
The NRC identified this apparent pattern of personnel errors to the licensee.
The licensee had not yet recognized or grasped the significance of this pattern of personnel errors.
Subsequently, several additional personnel errors occurred (see other paragraphs in, this report),
which prompted the licensee to begin to address the problems.
However, the errors were being addressed on an individual basis, not programmatically.
Following the reactor trip on September 8, the licensee delayed the restart while investigating the root cause specific to this error and to investigate possible programmatic flaws that had contributed to the recent increase in personnel errors.
The licensee's specific and general root cause efforts following this event were good.
Teams of Shift Supervisors (SSs)
were tasked with identifying root causes and recommending corrective actions to licensee management.
Additionally, an outside operations auditor was brought in for a different perspective.
The licensee's short term and long term corrective actions addressed a number of programmatic weaknesses and improvement opportunities.
The licensee's cot rective actions were good but the licensee's recognition of the pattern of personnel errors was not timely.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII of the NRC Enforcement Polic. 1.2 Reactor Tri Due to His-Ad 'ustment of the Control Rod Drive CRD Motor Generator MG Sets Unit 2 On August 29, 1995, Unit 2 tripped from full power due to high a negative neutron flux rate.'he negative flux rate condition occurred after both CRD-HG sets'utput breakers automatically tripped, allowing all control rods to insert into the core.
All safety systems responded as designed, with the exception of the two "W" HDAFW pump discharge valves.
The normally-open valves did not respond to a close signal following the trip, which resulted in excessive cooldown of the RCS and eventual letdown isolation due to low pressurizer level.
Operations department adjustment of the HG set voltage i
discussed in this paragraph.
Engineering involvement in MG set relay chattering is discussed in paragraph 3. 1.
The issue regarding the failure of the valves to respond is discussed further in paragraph 3.2.
The licensee determined that the
"S" CRD-MG output breaker tripped due to actuation of its directional overcurrent relay.
About seven hours prior to the trip, an auxiliary equipment operator (AEO) adjusted both CRD-MG sets'oltage regulators to stop chattering of the overcurrent relay contacts.
However, the adjustments resulted in an undetected load imbalance between the synchronized CRD-MG sets, which resulted in the eventual actuation of the relay.
During follow-up, the inspectors determined that the AEO did not have adequate procedural guidance to perform the adjustment.
The AEO used procedure OHP 4021.012.001,
"Operation of the Control Rod Drive System,"
as guidance, which was not applicable when the MG sets were synchronized.
In addition, the AEO did not receive sufficient oversight support from Operations shift management and system engineering, due primarily to poor communications between Operations and Plant Engineering and a perceived urgency to correct the problem.
On-shift licensee personnel were not aware that an imbalance could not be detected from the permanently installed instrumentation.
The inspectors determined that the licensee's failure to operate nl~~t equipment with adequate procedural guidance and oversight was a weakness.
The inspectors discovered that the chattering of the relays was an intermittent problem that had existed for several months.
The inspectors'oncern that the licensee had failed to take timely action to adequately address the degraded condition is discussed in paragraph 3. 1.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII of the NRC Enforcement Policy.
1. 1.3 Dama e To New Fuel Assembl GG10 Unit
On September 29, 1995, during routine refueling operations, a personnel error occurred and a new fuel assembly (FA) was heavily damaged.
Since the FA was new and no fuel pins were ruptured, there was no release of radioactive material.
Refueling operations were suspended and recovery planning was begu To allow a camera inspection of the bottom nozzle, the crane operator was required to position the FA lower than was normal.
Following the inspection, the operator forgot to raise the FA back to the normal height.
Mhen the fuel transfer cart/upender was raised, the FA was contacted and forced against the upender upper support.
The FA was damaged during this evolution, however as stated above, no pins were ruptured.
Licensee senior reactor operators (SROs)
were in control of fuel movement, however, fuel movement was being performed by contractor personnel.
The FA was recovered by Licensee and contractor personnel and placed into a
special support.
Structural damage prevented the FA from being placed in a normal storage location.
The irradiated rod cluster control assembly (RCCA)
that was in the FA will be removed and placed into another storage location.
The licensee did not plan to re-use the RCCA or the FA following this event.
The licensee and the fuel movement vendor initiated a root cause evaluation and determined:
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Additional management oversight was needed in the spent fuel pool area during refueling operations.
The inspection camera was placed too low to view the FA in the normal fuel movement position.
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There was a process added to the fuel movement that was not proceduralized (lowering the FA to be in range of an inspection camera).
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There was no detailed procedure for fuel movement in the Spent Fuel Pool (SFP).
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There were a number of marking tapes on the FA handling tool.
This increased confusion in determining the proper height of the FA.
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There were no automatic interlocks between the fuel handling bridge and the upender.
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The operator was not adequately monitoring upender operation.
After initiating the up motion, the operator would fill out his movement log instead of observing the upender.
The licensee and the fuel movement vendor initiated corrective actions to address the root causes listed above.
The inspectors interviewed personnel, reviewed the root cause evaluations, and then evaluated the licensees root cause and corrective action.
The root cause and corrective action appeared to be promptly performed and thorough.
Appropriate training, procedure revisions, and management expectations were implemented.
The inspectors reviewed this event and through interviews determined that the licensee's corrective actions failed to address two instances of inappropriate operator actio ~
Following the initial fuel damage, the upender operator attempted to lower the upender.
The upender overloads had tripped out making the upender inoperable, but the operator did not recognize the inoperability.
The u'pender operator tried three times to lower the upender.
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The inspectors were evaluating the FA position and damage early on the morning following the FA damage.
During that time an operator moved the fuel handling tool back and forth to check the tension on the cable.
The licensee failed to note the upender operators comments in his statement with regard to attempted upender movement after the fuel damage.
Additionally, the licensee failed to couple this errcr with the inappropriate fuel handling tool movement.
Once these items were pointed out by the inspector, the licensee recognized that the operators should be trained to leave damaged equipment alone unless properly authorized.
This training was performed prior to the resumption of fuel movement.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII of the NRC Enforcement Policy.
1. 1. <
Com onent Coolin Water CCW Low Flow - Unit
On September 18, 1995, with no fuel in the Unit 1 vessel, the inspectors identified during a routine walkdown of the control room panels that total CCW flow was lower than required.
The total flow was approximately 3500 gpm.
The inspectors discussed this condition with the operators and reviewed procedure Ol-OHP 4021.016.003,
"Operation of the CCW System During Reactor Startup and Normal Operation," that required flow greater than 4000 gpm for extended CCW pump operation.
The procedure allowed for flow between 3000 and 4000 gpm for a maximum of 30 minutes.
The inspectors learned that the operators had earlier realigned the system following flow balance testing, and had operated the
"W" pump with the low flow condition for approximately two hours.
As immediate action, the operators increased system flow above the minimum required.
The licensee also reviewed pump performance during the next surveillance test and no degradation was identified.
The licensee also initiated CR 95-1492 to document this event.
The licensee identified that the flow balance procedure contained a precaution at the beginning to maintain minimum flow but did not have a requirement to restore system alignment to ensure adequate flow.
Although a valid comment, the inspectors determined that operator awareness of plant conditions could have prevented the event.
The failure to maintain proper CCW flow in accordance with a procedure constitutes a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy.
1. 1.5 Loss of All Annunciators - Unit
On September 6,
1995, with no fuel in the Unit 1 vessel, an operator inadvertently de-energized the CD 250 Vdc Bus.
A licensed operator was isolating the CD battery for testing and transferring the load to the AB. dc bus per procedure 01-OHP 4021.082.013,
" Isolating, Transferring, and Restoring
a 250 Vdc Battery Load," when the operator failed to close the emergency tie For the AB battery, which was in series with the CD cross-tie.
Subsequently, when the operator isolated the CD battery, power to the CD bus was lost.
As a
result, all control room annunciators were de-energized and'some air-operated valves went shut.
The operators immediately took action to restore the CD bus.
The primary root cause for the event was personnel error.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII of the NRC Enforcement Policy.
1.2 0 erations Performance on Other Selected Issues 1.2. 1 Refuelin Activities Unit
60710 During the refueling outage, the inspectors observed the licensee's fuel handling operations and discussed refueling operations with plant operators and fuel handling personnel.
The licensee used approved procedures for fuel accountability and movements.
Communications between the control room and fuel handlers were established and effective.
The inspectors witnessed fuel handling operations during several shifts from the control room, in the fuel building, and in containment.
1.2. 1. 1 Command and Control As noted in paragraph 1. 1.3, the licensee had an event where a fuel assembly (FA) was damaged.
The licensee's root cause analysis identified one of the
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main contributors to be loose command and control as exhibited by inexact procedures, lax performance, and poor expectations.
1.2. 1.2 Forei n Material Exclusion Zones During a tour of the spent fuel pool (SFP)
and refuel pool foreign material exclusion zones (FHEZ)
on August 18, 1995, the inspectors observed numerous small foreign objects.
These were small pieces of glass, wood chips, scrap duct tape, pieces of heavy gage wire, insulation and other small pieces of debris.
The inspectors informed tool accountability personnel, the assistant plant manager, and the plant manager of this debris.
However, due to a
communications error by the licensee, only the SFP debris was removed.
The debris inside of containment remained while about 60 percent of the core was unloaded.
During a re-inspection of the FHEZ several days later, the inspectors identified the failure to remove the material and informed the licensee.
The material was removed and'a condition report (95-1246)
issued.
In addition to the foreign material (FH) identified by the inspectors, the licensee's organization identified various pieces of FH later in the outage.
These pieces of debris were removed and CRs written.
Initially, the licensee's FHEZ program was determined to be in need of improvement.
After changes were implemented, FHE was observed to improve but
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was still not strong, as items continued to be identified in the reactor vessel and inside of the FHEZ.
The licensee did, however, have a good program to search for, identify and remove F Review of future core inspections to assess effectiveness of the licensee actions to prevent foreign material intrusion in the core was a previous inspection follow-up item (IFI) (50-315/94024-02(DRP);
50-316/94024-02(DRP)).
In the 1994 inspection report, the inspectors documented the licensee's identification of FM on the lower reactor vessel core plate.
The licensee believed the items had fallen into the vessel during the then current refueling outage.
During this refueling outage the licensee continued to find FM on the lower core plate.
Most of these items were due to an improperly installed gasket (see paragraph 2.3 below).
However, there were some items which had fallen into the core (examples include a wrench and. some wire ties).
The inspectors will continue to leave this IFI open and observe licensee FMEZ practices around the open 'vessel during the spring refueling outage on Unit 2.
1.2.2 Auxiliar Buildin
'"e and Unusual Event - Both Units While Unit 1 was in Node 6 (refueling)
and Unit 2 was at full power, a fire was discovered in the roof of the auxiliary building.
The fire was caused by contractor maintenance activities on the roof.
Open flames were being utilized to lay down new roofing material around roof vent units.
Unknown to the roof installation crew, there were wooden supports (2 X 4's)
behind metal flashing.
Two boards caught fire and smoldered for about an hour.
In total, the amount of wood burned was about equal to the size of a soft-ball.
The inspectors determined that the licensee's response to the initial smoke
.alarms and reports of smoke in the auxiliary building was prompt and professional.
Operators were dispatched to investigate the smoke and determine a cause.
When the refueling crew reported seeing flames in the roof, the plant fire brigade was dispatched and fuel movement was suspended.
By the time the fire brigade reached the roof, the fire had been put out by the workers using drinking water, Interviews with the job site foreman revealed that the roofing crew was, not cognizant of the wood behind the flashing.
The licensee had already identified this information as part of the root cause investigation.
The licensee determined that the contractor had been issued drawings in the bid package which showed the wooden supports.
When the contractor issued the installation drawings, the wood was left out.
When the bid was reviewed by the lic nsee, the contractor drawings contained within the bid ere not reviewed.
Additional reviews and corrective actions were ongoing at the end of the report periods The fire was small and easily contained.
The event was self-revealing and pointed out a minor weakness in the licensee's review of bid packages for non-safety related contracted work.
1.2.3 Main Transformer Failure and Unusual Event - Unit
At 12:49 a.m.,
on August 20, 1995, while testing the newly-installed Unit
main transformer on backfeed from the grid, an explosion occurred due to the failure of the phase 2 output bushing.
Shortly after, the licensee declared an Unusual Event as required by plant procedure due to an explosion onsite with potential to affect plant operations.
There was no effect on plant
systems, as the transformer was not providing power to the buses.
In addition, protective relaying functioned as designed to isolate the transformer from the grid.
After verifying no additional plant equipment was damaged from the explosion and that no personnel injuries occurred, the licensee canceled the Unusual Event at 1:50 p.m.
The spare transformer was installed following the main generator over-excitation event on July 16, 1995, and had been energized for approximately
hours for testing prior to the explosion.
The licensee was able to obtain a
replacement transformer from another company site which was tested satisfactorily.
During the latest test, the licensee used a low amperage power source and applied the voltage in a controlled manner to identify potential flaws in a less catastrophic manner.
2. 0 NAINTENANCE NRC Inspection Procedures 62703 and 61726, and 92902 were used to perform an inspection of maintenance and testing activities.
The licensee was conservativo in expanding the inspections and repairs of questionable electrical sealing connections, and in looking for gasket debris in the RCS and connected systems.
There was one unresolved item related to the licensee's method of testing the emergency diesel generators.
2. 1 Maintenance and Surveillance Testin Activities The inspectors observed routine preventive and corrective maintenance and surveillance activities to ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes or standards, and in conformance with Technical Specifications.
The following activities were observed and/or reviewed:
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JO¹ C0032242,
"Troubleshoot/Repair Trip Caused By 2-MLS-418"
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JO¹ C0029811,
"Adjust Settings of 2-MLC-407 and Stroke 2-MRV-427"
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JO¹ C0029857,
"Adjust Settings of 2-MLC-405 and Stroke 2-MRV-425"
JO¹ v0030255,
~@move, Inspect, and Repair Check Valve 2-CCW-176E" JO¹ C0026350,
"Replace Expansion Joints Check Valve 2-CCW-176E" 2.2 Environmental uglification of Certain Electrical Connections Both Units On August 25, 1995, during the Unit 1 refueling outage, the licensee identified that environmentally qualified (Eg) seal assemblies on electrical connections for the reactor head vent solenoid valves had been previously improperly installed.
Upon further investigation, the licensee determined that similar connections for the reactor head vent valves and the pressurizer power operated relief valve (PORV) acoustic monitoring system for both units, and a
PORV limit switch indication cable on Unit 1 were also improperly
installed.
The installation deficiencies consisted of the connectors on all the assemblies having insufficient torque applied to provide a qualified seal, and several assemblies missing a ferrule which was necessary to adequately seal the assembly.
Unit 2 was in Mode 3 when this condition was identified.
Unit 2 was cooled down to mode 5, and repairs to all affected assemblies were completed.
Repairs to Unit 1 were incorporated into the outage schedule.
The installation deficiencies were encountered because the licensee's procedure did not incorporate the vendor's recommendation regarding torque requirements.
Although the reactor head and pressurizer vent valve assemblies were replac d each refueling o~~tage, the installation deficiencies were assumed to have existed since original installation because the same procedure had been used.
The licensee was not able to determine the cause for the missing ferrules.
The Eg requirements for the electrical connections were based on generic conditions designed to bound the most limiting conditions that could be expected at any plant.
The licensee's inv"stigation determined that although the as-found "ondition of the connections did not meet the vendor Eg design envelope, it was sufficient to ensure operability of the components based on conditions expected to be encountered during specific accident scenarios at the Cook plant.
The licensee performed additional testing to support these conclusions.
The inspectors concluded that the licensee exhibited good conservative decision making by investigating Unit 2 for problems similar to those identified on Unit
and in the decision to cool down to Mode 5 to perform the necessary repairs.
2.3 Gasket Debris in Reactor Coolant S stem RCS and Emer enc Core Coolin S stem ECCS
- Unit
During the current Unit 1 outage, the licensee discovered pieces of flexitallic gasket on the bottom of the reactor core and during inspections of SI accumulator outlet valves 1-SI-166-L2 and 1-SI-166-L3.
The licensee determined that the source of the gasket material was from I-IRV-311, RHR heat exchanger bypass control valve.
The licensee apparently installed an undersized gasket during maintenance on the valve in 1994.
The licensee performed flushes of the ECCS pumps'ischarge piping to remove any remaining material'n those lines.
In addition, due to a concern that material located in the suction piping could potentially damage the Sl and CCP pumps, the licensee installed a cleanout connection in the header and performed an internal inspection.
The licensee discovered additional gasket material in the piping, The licensee also performed an investigation and determined that the use of the undersized gasket during the valve maintenance was an isolated incident.
The inspectors concluded the licensee's actions to recover the loose debris were thorough.
2.4 Emer enc Diesel Generator EDG Pre-Conditionin Prior To Testin Both Units The inspectors identified a concern regarding the potential pre-conditioning of EDG air start valves which receive an open signal on an auto EDG start.
The licensee's policy was to roll the EDGs on air with the cylinder petcocks open prior to the surveillance.
This was done to prevent damage to the EDGs in the event of excessive water or oil accumulation in the cylinders.
The licensee monitored the fluid blown from the petcocks in the past and had not observed excessive amounts which would question EDG operability.
However, the inspectors were concerned that, since the air start valves were cycled to support the b'.lowdown evolution, the valves were not being tested in an as-found condition.
The cycling of the valves pri-r to a timing test could mask a problem that would prevent the EDG from performing as designed.
The inspectors noted that Regulatory Guide 1. 108, "Periodic Testing of Diesel Generator Units Used As Onsite Electric Power Systems At Nuclear Power Plants," stated that cranking or venting procedures that lead to the discovery of conditions that would have resulted in the failure of the EDG to perform as intended should be considered a valid test and failure.
The licensee documented the inspectors'oncern in CR¹ 95-1243.
The licensee had not responded to the inspectors concern but was in the process of reaching a
formal position regarding whether this activity was pre-conditioning.
The inspectors'eview of the licensee's response is an unresolved item (50-315/316-95010-01).
3. 0 ENGINEERING NRC Inspection Procedure 37551 was used to perform an onsite inspection of the engineering function.
During this report period several self-revealing, licensee identified, and inspector identified issues showed weaknesses in the licensee's review and close-out of issues.
There were multiple examples of problems not being addressed in a timely manner and there were multiple examples of corrective actions not being complete.
3. 1 Inade uate Action to Address MG Set Chatterin Rela s
Unit 2 As discussed in paragraph 1. 1.2, the intermittent chattering relay problem with the CRD-MG sets which caused the Unit 2 trip had existed for several months.
Operators had typically performed the adjustments to stop the intermittent chattering problem in the past, with I&C support using some temporarily installed instrumentation.
Plant engineering had scheduled an evolution to troubleshoot the problem at the end of the present cycle when all control rods were installed in the core, due'to the possibility of an inadvertent reactor trip.
The inspectors reviewed the licensee's investigation into CR 95-1128, dated August 2, 1995, which documented the intermittent chattering problem.
The investigation documented a meeting that was held between representatives of Operations and Plant Engineering on March 3, 1995, to discuss the issue.
The intent of the meeting was to discuss the feasibility of allowing operators to make adjustments to the MG sets without I&C support.
Operations responded that the operators did not have the qualifications to perform the adjustments.
The parties agreed at that point that a lesson plan needed to be developed to train the operators to perform the task.
However, the lesson plan was never developed, and the licensee agreed later to continue to have 18C support Operations in making the adjustments.
This policy was apparently not communicated properly to Operations shift personnel.
The investigation into the reactor trip determined that the operators, on occasion, were performing the adjustments without I&C support, including the latest example that resu',ted in the trip.
The inspectors concluded that the licensee did not take adequate action in the short term to address the degraded relay condition.
The licensee also identified a problem with the system ovi>>voltage relays during the investigation.
There were two CRD-HG sets and only one was required to maintain power to the control rods.
A single set was designed to maintain bus voltage in the event of the loss of the other set.
However, the "N" CRD-HG set tripped seconds after the other set tripped, due to actuation of the common bus overvoltage relay.
The licensee determined that the relay had actuated at 240 Vac instead of the desired setpoint of 300 Vac.
Normal bus voltage was 260 Vac, and the licensee estimated that the bus voltage increased to 285 Vac after the "S" CRD-HG set tripped.
The inspectors determined that the system relays had not been calibrated since installation in 1992's corrective action, the licensee replaced the bus overvoltage relay and calibrated the other system relays.
The licensee also established a new calibration frequency for the relays.
In addition, the licensee issued written directions to Operations to contact Plant Engineering if regulator adjustments were desired.
The licensee revised procedure OHP 4021.012.001 to enhance the method used to balance the sets using line current wave form measurements, Also, the licensee posted visual aids on the set control panels to indicate normal operating range.
3.2 Poor Evaluation of Tor ue Switch Set pints Unit 2 The licensee determined that the failure of the
"W" NDAFW pump discharge valves to operate following the Unit 2 trip, as discussed in paragraph 1. 1.2, was due to improper torque switch trip setpoints on the motor operators.
The licensee reduced the setpoints in early 1995 to improve the margin between the setpoint and the thermal overload trip of the motor operator supply breaker when operating under degraded voltage conditions.
The trip setpoints were also based on what was believed to be the highest thrust demand for globe valves, a high flow/high differential condition.
However, the licensee determined that, due to the unique design of the valves which provided a flow control feature, a low flow/high backpressure condition, which typically existed following a reactor trip, created the highest thrust demand.
As corrective action, the licensee adjusted the switches to the previous setpoints.
The inspectors will follow-up on the licensee's resolution of the degraded voltage as part of a previously documented unresolved item, ¹315/316-93006-01(DRS).
The inspectors concluded that the failure to ensure the most conservative conditions were used to set the MDAFWP discharge valves torque switch was a weakness.
3.3 Tri on Hi h Moisture Se arator Re-Heater Level Unit 2 On August 26, 1995, Unit 2 tripped on an apparent high level in the West moisture separator re-heater (HSR) drain tank.
The apparent high level caused the main turbine to trip. and this resulted in an automatic reactor trip.
All equipment operated as designed with the exception that one of the two source range monitors displayed an abnormally low count rate.
At the time of the trip the licensee had been performing main turbine valve testing.
The inspectors responded to the plant and assessed the licensee's analysis of the root cause and observed their corrective actions.
The licensee determined that there had been no actual high level and the trip was spurious.
If a high level had existed, the high and high-high level alarms would have annunciated prior to the trip.
These alarms did not annunciate and were tested successfully after the trip.
The licensee determined that the turbine valve testing created temporary indicated high level in the West HSR trip instrumentation.
The trip instrumentation was separate from the alarm instrumentation.
The licensee believed that the trip instrumentation momentarily picked up due to piping configurations and other differences.
The licensee's corrective actions included:
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Testing all West HSR drain tank level instruments and verification of proper operation.
~
Deleting the trip function of both the East and West HSR drain tank trip instruments.
The trips will annunciate but will not automatically initiate a trip of the main turbine.
~
Revising the plant procedures to direct the operators to manually trip the main turbine if original high or high-high level annunciators alarm and the high level trip annunciator al'arms.
~
The source range monitor was re-calibrated and returned to service.
The inspectors review of the turbine/reactor trip noted:
There have been a total of four reactor trips on Unit 2 due to high HSR drain tank level.
The last one occurred on December 11, 1994, when unit 2 tripped during a startup.
The licensee did not conclusively determine the cause of the spurious high level trip.
As in the August 26, 1995 event, the high and high-high annunciators did not actuate prior to the trip.
The licensee determined that the high and high-high level switches were corroded.
The switches were repaired and added to the preventive maintenance program (PH).
The inspectors reviewed the PH program and verified the switches had been added.
The licensee lost an opportunity to identify the problem with the HSR drains following the 1994 trip and the earlier trips.
The root cause evaluations and corrective actions were not carried forward far enough.
The inspectors noted a minimal number of items were worked on the licensee's forced outage list.
This was due to the short duration of the unplanned outage and the need for resources on the Unit 1 refueling outage.
During the review of the licensee's safety review for the temporary modification that removed the turbine trip on high HSR drain tank level, the inspectors noted that the review did not address possible increases in the probability of turbine generated missiles.
The licensee's final safety analysis report (FSAR) addressed turbine generated missiles due to overspeed events.
The FSAR did not address missiles generated due to water intrusion into a spinning turbine generator.
The licensee did discuss water intrusion causing damage to the turbine in the meeting which approved the temporary modification.
This discussion included whether the temporary modification would result in an increased probability of an accident.
The licensee decided that the increased probability was negligible.
This information should also have been documented in the safety review of the temporary modification.
3.4 Stuck 0 en Com onent Coolin Water CCW Check Valve Unit 2 On September 19, 1995, during performance of surveillance procedure
- 02-OHP 4030.STP.020W,
"West Component Cooling Water Loop Surveillance,"
the licensee identified that the Unit 2 East CCW pump discharge check valve (2-CCW-176E)
was stuck in the open position.
Because of the resulting backflow through the East CCW pump, the operators declared both CCW trains inoperable and entered TS 3.0.3.
The TS was exited a few minutes later when cross-tie valves were closed, and the West CCW pump was declared operable.
The check valve was replaced and returned to service.
During performance of surveillance procedure
was manually opened in small increments, in an attempt to prevent the check valve from slamming closed.
With the cross-tie approximately 5-6 turns open, 2-CCW-176E remained open and an estimated 1000 gpm was flowing backwards through the East CCW pump.
The operators declared the check valve inoperable and closed the cross-tie valve.
The licensee performed an investigation as to the cause of the check valve becoming stuck on September 19, and an evaluation to determine the operability of the West CCW train at the time the check valve became stuck.
The licensee determined that the valve stuck open because of a combination of a bent stem and corrosion build-up on the disc plates.
A computer model that the licensee was developing of the CCW system was used to support calculations that showed that the West CCW pump could provide sufficient flow to design basis loads with 2-CCW-176E partially open.
The inspectors reviewed licensee actions regarding 2-CCW-176E prior to and after the surveillance on September 19, 1995.
Since various parts were replaced during a refueling outage in October 1994, 2-CCW-176E had exhibited the following history of "sticking" and slamming closed:
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October 12, 1994
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April 17, 1995
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Hay 31, 1995.
The first recorded instance of excessive slamming occurred during a switch from the east to the west pump.
The system engineer evaluated the condition, and observed three pump swapovers.
During those swapovers no check valve slam was evident.
The licensee determined that no action was necessary at that time.
Slamming of the check valve was observed.
The slamming was significant enough to cause an auto-start of the East CCW pump and initiation of fire alarms due to the amount of dust released in the area.
~
September
During a
TS surveillance the discharge cross-tie valve was opened in small increments.
With the cross-tie approximately 5-6 turns open, 2-CCW-176E remained open and an estimated 1000 gpm was flowing backwards through the East pump.
The operators declared the check valve'noperable and closed the cross-tie valve.
The licensee's actions to CCW-176E should have been importance.
According to CCW is the most important frequency.
evaluate and resolve the degraded condition of 2-more timely, as commensurate with CCW system the licensee's Individual Plant Examination (IPE),
system with regards to reduction of core melt The inspectors also noted a weakness in the licensee's controls for vendor-initiated equipment modifications.
The vendor for the subject check valve had made a design change which required additional parts (stop-plates)
to be installed with the valve internals.
2-CCW-176E and 3 similar valves in the essential service water system were identified as not having the required stop-plates.
However, following inspection of 2-CCW-176E, the licensee determined that a lack of stop-plates did not contribute to the check valve failure.
The inspectors reviewed the licensee's evaluation of operability of the CCW system in the as found configuration (176E stuck part way open).
The inspectors found the evaluation to be confusing, disjointed, lacking in detail and dependant upon a
CCW system flow model that was not officially approved.
In response to the inspectors'oncerns, the licensee revised the evaluation and eliminated reliance upon the system model.
The system flow model was almost through the licensee's approval cycle and was used as supporting evidence.
The revised evaluation was much clearer and contained more detail.
3.5 Poor Root Cause Evaluation of "W" Motor Driven Auxiliar Feedwater Pum In response to questioning from the inspectors, the licensee determined that the initial corrective action for a spurious instantaneous trip of the West HDAFWP which occurred on 18 August 1995 was inadequate.
The inspectors were concerned due to a history of spurious instantaneous trips with the most recent previous trip occurring on February 28, 1994.
During routine follow-up to a spurious trip of the
"W" HDAFWP the inspectors determined that licensee personnel were unable to identify any specific root cause.
After checking the overcurrent relays, the licensee restored the pump to service (at the time all fuel was unloaded from the reactor vessel and the HDAFW pumps were not requi, d to be operable).
The inspectors reminded the assigned system engineer of the previous spurious trip of the
"W" HDAFWP on February 28, 1994, and informed licensee management that repeated spurious trips of equipment should call into question its reliability.
In response to the inspectors'oncerns, the licensee performed additional testing of the overcurrent trip relays.
The relays were found to need adjustment due to not having an adequate margin for motor starts under high bus voltage conditions (usually encountered during outages when the buses are lightly loaded).
This event, together with the Unit 2 trip due to a spurious high moisture separator level, and the Unit 2 trip following adjustment of the CRD HG set represented three examples of the licensee's failure to learn from and properly correct problems during their first occurrence.
3.6 Dama ed Reactor Core Barrel Former Bolts - Unit
During this refueling outage the licensee inspected the reactor core barrel looking for damaged former bolts.
The licensee identified one missing former bolt (A-5) and two former bolts (A-4, and A-6) that were loose.
The licensee removed the two loose bolts, checked to ensure that no other bolts were loose or missing, and performed an evaluation to ensure safety would not be compromised while operating with three missing bolts.
The inspection was performed due to the discovery of a former bolt resting on the bottom of reactor vessel core support plate during the last refueling outage (Spring 1994).
The former bolts can only be inspected with the core barrel removed.
During the 1994 refueling outage, there had been no plans to remove the core barrel so the licensee evaluated postponing plans to look for the original location of the mi"sing bolt until the 1995 refueling outage.
The licensee's evaluation was reviewed by the NRC and documented in inspection report No. 50-315/316-94005(DRP).
The three damaged bolts were located next to each other on the same elevation (the "A" elevation).
The licensee and their contractor believed that the bolts were damaged due to localized stress induced by a thermal shield support.
The licensee was unable to explain why damaged bolts were not being identified at the other support locations, in the other reactor on site, or in
i(,
other nuclear reactors in the United States.
The licensee's proposed course of action (to identify and correct the root cause),
and justification for restart were reviewed by the NRC.
No significant comments were identified.
The licensee committed to the following; additional inspection of the Unit
former bolts during the next refueling outage (Spring of 1997), evaluation of this issue for applicability to Unit 2, and the vendor agreed to evaluate this issue for potential 10.CFR Part 21 concerns.
3.7 Steam Generator Edd Current Ins ection Pro ram Unit
73753 73755 73052
<e The overall performance of steam generator (SG) inspection act'vities was considered good.
The eddy current exami."."tiun of SG tubes consisted of 100X of all open tubes using the bobbin coil, 100X top of the tube sheet area (+3" above tubesheet to tube end) using a motorized rotating pancake probe (HRPC),
100X examination of sleeved tubes using the Westinghouse Cecco probe. All row one and two U-bends in SG 14 were examined using a special HRPC probe.
Westinghouse personnel performed the primary data analysis and Conam (Rockridge)
personnel performed the secondary analysis, the resolution analysts were Westinghouse and Conam ET level III. All ET analy=ts were qualified to level IIA or III and certified by site specific examination prior to performing data analysis.
A significant number of tubes were recovered (125)
by removal of tube plugs and reinspection to recently approved inspection and repair criteria.
The F*
criteria for tube roll transition and the Interim Plugging Criteria (2 volt)
for support plate axial indications were approved by NRR and implemented for the recovery of these tubes.
The majority of the indications identified this outage occurred in the hot leg roll transition area of the'G tubing.
A total of 105 tubes were plugged this outage, of which 20 were replugs after unplugging.
A total of 1039 SG tubes were repaired utilizing the F* reroll criteria, of which 117 were reclaimed tubes.
All SG tubes which were rerolled were reexamined in accordance with the F* requirements and verified to have no indications within the reroll tube area within the required F* dimensions.
The NRC inspector observed the eddy current examination in process, observed the data a.. lysis re.
u'ion analyst reviewing and dispositioning data, reviewed the data analysis guidelines, ET acquisition procedures, certifications of ET equipment and pe", sonnel, indication graphics, indication list, and verified the indications were dispositioned in accordance with the applicable procedures.
Review of reroll inspection records (sampling)
confirmed the ET analysis for the rerolls were recorded and acceptable.
All tubes repaired by plugging utilized Westinghouse Inconel 690 mechanical plugs.
4.0 PLANT SUPPORT NRC Inspection Procedures 71750, 83750, and 92904 were used to perform an inspection of plant support activities.
Total plant dose was within goal even though the Unit 1 refueling outage came earlier and lasted longer than was expected.
4. 1 Radiolo ical Controls The inspector reviewed As Low As Reasonably Achievable (ALARA) program performance and initiatives implemented during the on-going refueling outage (U1R95).
Selected work areas were also reviewed during tours of the auxiliary and containment buildings.
Several workers were interviewed to determine their understanding of the job requirements and area dose rates, with no problems identified.
The inspector also toured upper and lower containment, auxiliary, and turbine buildings.
Overall, housekeeping, material condition, and radiation protection technician (RPT) job coverage was good, and workers i".. containment were aware uf radiological conditions.
The U1R95 outage had slightly lower than anticipated general area dose rates due in part to longer run times of the reactor coolant pumps during the chemical cleanup of the reactor coolant system.
Although there was no chemical decontamination performed on the Regenerative Heat Exchanger (RHE)
and the Resistance Temperature.Detector (RTD) loops, it appears the primary cleanup initiative was effective in removing considerable radioactivity from the reactor systems.
Although UlR95 began about six weeks ahead of schedule, the licensee appeared to perform radiation protection (RP) functions (selection of contract technicians, developing Radiation Work Permits, ALARA reviews and initiatives, etc.) well and sufficiently implemented radiological controls for outage activities.
The outage was scheduled for about 45 days but was behind schedule due to emergent work caused by identified problems with the core barrel and damage to a new fuel assembly (both issues were discussed earlier in this report).
The projected dose goal for the UIR95 outage was about 250 person-rem (2.5 person-Sv),
and with the outage almost finished the dose was about 142 person-rem (1.42 person-Sv).
The lower than projected dose was the result of some reduced and canceled work, good planning, and effective ALARA implementation.
During this report period the inspectors identified four examples of degraded postings.
Three examples consisted of ropes being down for contaminated areas.
In all three cases, the step off pads and signs were in place, The fourth barrier consisted of a missing danger high radiation sign to lower containment.
When notified the licensee replaced the barriers and initiated condition reports as required.
4.2 Follow-u on Previousl 0 ened Items A review of the following previously opened unresolved and inspection follow-up items was performed per Inspection Procedure 92901.
4.2. 1 Closed LER 50-315 94-005 Failure of Fire Watch Personnel to Perform Assi ned Duties Resultin in Hissed Tech S ecs Re uired Surveillance.
In June 1992, the fire protection system for multiple areas of the plant was declared inoperable due to uncertainties regarding the fireproofing material.
I (5
Immediate compensatory measures were taken as required by Tech Specs.
However, during a record review conducted by the licensee, a number of discrepancies were identified regarding failures to establish an hourly fire watch patrol.
Hany of these discrepancies were attributed to one individual who is no longer employed by the licensee.
The inspector verified that the following corrective action were implemented:
FP.994, Administrative Guideline to Monitor Fire Protection Tour/Surveillance, was developed to monitor a ten percent random monitoring program for fire watch tours;'the security card reader access status for all fire watches has been upgraded; and fire watch training was conducted to review the lessons learned from +"..'.s event.
This item is closed.
4.2.2 Closed LER 50-315 94-009 Re uired Continuous Fire Match Post Not Established Due to Inade uate Administrative Controls.
While Unit 1 was operating at 100X on July 12, 1994, a portion of the fire protection system was out of service for component repairs.
The Contractor Access Control Area, fire zone 0105, is required to be under a continuous fire watch patrol per Tech Spec 3.7.9.2.b when the fire suppression system for this area is inoperable.
The, licensee discovered that the required fire watch had not been established and immediately posted a fire watch in the affected area.
The inspector confirmed that the following corrective actions were taken by the licensee:
PHSO. 122 forms are coordinated with the centralized clearance group two weeks earlier; fire protection group will be notified by operation personnel prior to hanging clearances and after clearance restoration; and the Fire Protection Group will use the Nuclear Plant Haintenance System to verify component status.
This item is closed.
4.2.3 Closed LER 50-315 94-014 Weekl Gaseous Grab Sam le Not Taken Due to Personnel Error.
On January 6,
1995, the licensee discovered that the plant Gland Seal Exhaust weekly gaseous effluent grab sample for the period of December 17-25, 1994 was not completed.
The event was attributed to personnel error.
The individual involved in conducting the monthly surveillance requirement mistakenly marked the line item for the gaseous sample as
"Not Applicable"(N/A).
The licensee attributed the error to a lack of attention to detail.
A contributing factor to this error was also the ambiguity of the Nuclear Tracking System (NTS) schedule form.
The form did not clearly define surveillance frequencies and the Tech Spec requirement for the sampling activities.
As corrective action to prevent reoccurrence of this type event, the licensee modified the NTS surveillance schedule sheet.
The sheet now contains only Tech Spec required surveillances.
The administrative entries are no longer included on these sheets'he use of "N/A" on the NTS surveillance schedule form has been prohibited.
Additionally, the appropriate staffs have been briefed on the above procedure changes.
This item is closed.
r
~o
No violations or deviations were identified.
5.0 PERSONS CONTACTED AND MANAGEMENT MEETINGS 5.1 Mana ement Meetin On October 18 and 19, 1995, there was a site visit by the Region III Director, Division of Reactor Projects and Director, Division of Reactor Safety, along with the Acting Project Directorate, III-I from NRR.
During the visit, these individuals, along with other NRC staff, conducted a plant tour and interviewed various plant personnel.
At the conclusion of the visit, a
meeting was convened with the '.'.censee to discuss the following major observations:
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The recent increase in the number of human performance issues was uncharacteristic of the licensee's past performance.
The corrective actions appear to address the issues.
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Material condition and housekeeping continues to be above average.
o The licensee's identification of operator workarounds was considered aggressive.
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The licensee has been aggressive in minimizing any adverse impact on plant operations.
The control of Zebra mussels has been a licensee high priority.
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Source term continues to be low.
5.!
E i<<i The inspectors contacted various licensee operations, maintenance, engineering, and plant support personnel throughout the inspection period.
Senior personnel are listed below.
At the conclusion of the inspection on October 26, 1995, the inspectors met with licensee representatives (denoted by *) and summarized the scope and findings of the inspection activities.
The licensee did not identify any of the documents or processes reviewed by the inspectors as proprietary.
- A. A. Blind, Site Vice President/Plant Manager
- K. R. Baker, Assistant Plant Manager-Operations
- J.
R.
Sampson, Assistant Plant Manager-Support
- D. L. Noble, Radiation Protection Superintendent
- T. K. Postlewait, Site Engineering Support Manager
- J.
S. Wiebe, Superintendent, Plant Performance Assurance
- R. Rickman, Operations Production Supervisor
- W. M. Hodge, Plant Protection Superintendent
- J. Rutkowski, Assistant Plant Manager
- G. A. Weber, Superintendent, Plant Engineering
- H. E. Barfelz, Superintendent, Nuclear Safety
& Analysis
I t
- R. Hankowski, Supervisor, NETS
- J; D. Allard, Haintenance Superintendent
- D. 0. Horey, Chemistry Superintendent
- D. H. Fitzgerald, Superintendent, Environmental, Safety and Health
- T. P. Beilman, Superintendent, Integrated Scheduling
- T. E. guaka, Superintendent, Project Hanagement and Installation Services
- H. Depuydt, Nuclear Safety and Assurance Engineer
- D. Londot, General Supervisor, IHS
I