IR 05000387/1993011
| ML17157C466 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 08/27/1993 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17157C465 | List: |
| References | |
| 50-387-93-11, 50-388-93-11, NUDOCS 9309140196 | |
| Download: ML17157C466 (24) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
Inspection Report Nos.
50-387/93-11; 50-388/93-11 License Nos.
Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:
Inspection At:
Susquehanna Steam Electric Station Salem Township, Pennsylvania Inspection Conducted:
June 29, 1993 - August 17, 1993 Inspectors:
G. S. Barber, Senior Resident Inspector, SSES D. J. Mannai, Resident Inspector, SSES A.
Lohmeier, Senior Reactor Engineer, Materials Section, DRS J. C. Tsao, Materials Engineer, NRR B. J. M'Dermott, Reactor Engineer, DRP Approved By:
J. White, Ch Reactor Projects Section No. 2A, D te Tdd d
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p (during day and backshift hours) of station activities, including: plant operations; radiation protection; surveillance and maintenance; and safety assessment/quality verification.
Findings and conclusions are summarized in the Executive Summary.
Details are provided in the full inspection report.
9309140196 930831 PDR ADOCK 05000387 Q
EXECUTIVE SUMMARY Susquehanna Inspection Reports 50-387/93-11; 50-388/93-11 June 29, 1993
- August 17, 1993 Operations (30702, 71707, 71710)
On July 12 at 4:35 p.m., Unit 1 scrammed following the main turbine trip on high vibration.
Operators responded to the transient by entering appropriate off-normal procedures.
The licensee determined the plant responded per design.
The inspector concluded the operators properly responded to the event and plant safety systems operated per design.
Section 2.2.1 pertains.
Radiological Controls (71707)
The licensee contaminated three elevations of the Unit 1 Reactor Building during a backwash of the Unit 1 Fuel Pool Cooling Filter Demineralizer.
The licensee identified a design weakness with the use of a pressurized backwash and a partially clogged exhaust filter on the backwash receiving tank as root causes.
Compensatory actions have been implemented while potential design changes are being evaluated.
The inspector determined that the licensee actions were appropriate.
Section 3.2.1 pertains.
Maintenance/Surveillance (61726, 62703)
The licensee discovered some unacceptable scratching on six of sixteen cylinder liners for the
"D" Emergency Diesel Generator (EDG) during its five year overhaul.
The scratching was traced to a 1990 sandblast grit intrusion.
No adverse effect was detected during operations since the "D" EDG satisfactorily completed all its required surveillance testing during operations.
All six of the affected liners were replaced.
The inspector determined that licensee actions were appropriate and conservative.
Section 4.4.1 pertains.
Engineering/Technical Support (71707, 92720, 93702)
During the period, the Unit 1 turbine tripped due to high vibration; and the reactor scrammed following the turbine control valve fast closure.
PP&L determined the high vibration was caused by the failure of two I 1 Row buckets on the "C" low pressure turbine.
The licensee prepared an interim root cause evaluation report which concluded that high cycle fatigue caused the turbine bucket failure. This item is unresolved pending final review by the NRC.
Section 7.2.1 pertain Safety Assessment/Quality VeriTication (40500, 90712, 92700, 92701)
A semiannual surveillance of the reactor protection system (RPS) electrical protection assembly (EPA) breakers necessitated securing shutdown cooling (SDC) with a high decay heat load.
Since reactor recirculation and reactor water cleanup (RWCU) were also out-of-service, temperature indication was unavailable for the 51 minutes it took to complete the surveillance.
Operators were aware that temperature indication would be unavailable, and, as a result, lowered reactor temperature to a minimum value (106.5'F).
However, the inspector noted that no coherent plan existed to manage and limitshutdown risk for this evolution.
The licensee is continuing to evaluate the appropriate controls on shutdown risk for this issue.
Section 8.2 pertain TABLEOF CONTENTS EXECUTIVE SUMMARY SUMMARYOF OPERATIONS.
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1.1 Inspection Activities......
1.2 Susquehanna Unit 1 Summary 1.3 Susquehanna Unit 2 Summary
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OPERATIONS 2.1 Inspection Activities......... ~..............
2.2 Inspection Findings and Review of Events 2.2.1 Reactor Scram Due to High Turbine Vibration...
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RADIOLOGICALCONTROLS 3.1 Inspection Activities........................
3.2 Inspection Findings 3.2.1 Fuel Pool Filter Demineralizer Backwashing Causes Contamination.......................
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'AINTENANCE/SURVEILLANCE 4.1 Maintenance and Surveillance 4.2 Maintenance Observations..
4.3 Surveillance Observations 4.4 Inspection Findings 4.4.1
"D" Emergency Diesel
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Inspection Activity..
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Generator Overhaul
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EMERGENCY PREPAREDNESS 5.1 Inspection Activity.......
5.2 Inspection Findings
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SECURITY 6.1 Inspection Activity.......
6.2 Inspection Findings 7.
ENGINEERING/TECHNICALSUPPORT 7.1 Inspection Activity.............................
7.2 Inspection Findings 7.2.1 Unit 1 Turbine Blading Failure
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TABLEOF CONTENTS (CONTINUED)
8.
SAFETY ASSESSMENT/QUALITYVERIFICATION..........
8.1 Open Items
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8.2 Unavailability of Temperature Indication During Cold Shutdown
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MANAGEMENTAND EXITMEETINGS.....................
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9.1 Resident Exit and Periodic Meetings.....................
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9.2 Inspections Conducted By Region Based Inspectors..............
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Details 1.
SU1VMARYOF OPERATIONS 1.1 Inspection Activities The purpose of this inspection was to assess licensee activities at Susquehanna Steam Electric Station (SSES) as they related to reactor safety and worker radiation protection.
Within each inspection area, the inspectors documented the specific purpose of the area under review, the scope of inspection activities and findings, along with appropriate conclusions.
This assessment is based on actual observation of licensee activities, interviews with licensee personnel, measurement of radiation levels, independent calculation, and selective review of applicable documents.
Abbreviations are used throughout the text.
Attachment 1 provides a listing of these abbreviations.
1.2 Susquehanna Unit 1 Summary Unit 1 began the inspection period at 100% power.
On July 6 through 10, there were five small (2-4%) power reductions due to high condenser back pressure.
They varied in duration from three to fourteen hours due to high ambient temperature conditions.
Operators returned power to 100% as ambient conditions permitted.
On July 12, Unit 1 scrammed due to a turbine control valve fast closure.
The turbine tripped on high vibration.
Sections 2.2.1 and 7.2.1 pertain.
On July 15, shutdown cooling was secured for 51 minutes to perform SO-158-003, "Semi-annual RPS Electrical Power Monitoring Assemblies Channel Functional Test."
During this period, primary coolant temperature indication was unavailable.
Section 8,2 pertains.
Operators conducted several other routine power reductions during the inspection period to facilitate control rod pattern adjustments and surveillance testing.
Unit 1 finished the inspection period in Condition 4.
1.3 Susquehanna Unit 2 Summary Unit 2 began the inspection period at 100% power.
On July 6 through 10, there were five small (2-4%) power reductions due to high condenser back pressure.
They varied in duration from four to ten hours due to high ambient temperature conditions, Operators returned power to 100% as ambient conditions permitted.
On July 14, the offgas system isolated on a high-high hydrogen signal.
Power was reduced to 93% to maintain condenser vacuum per ON-243-001, "Loss of Condenser Vacuum" and
ON-272-001, "Offgas System Isolation."
Chemistry sampling showed that the hydrogen levels were normal.
Operators bypassed the high-high signal, restored condenser vacuum, and returned the unit to 100% power that day.
Operators conducted several other routine power reductions during the period to facilitate control rod pattern adjustments, surveillance testing, and maintenance.
No reactor scrams or ESF actuations occurred during the inspection period.
Unit 2 finished the period at 100%
power.
2.
OPERATIONS 2.1 Inspection Activities The inspectors verified that the facility was operated safely and in conformance with regulatory requirements.
Pennsylvania Power and Light (PPScL) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility records.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
2.2 Inspection Findings and Review of Events 2.2.1 Reactor Scram Due to High Turbine Vibration On July 12, 1993, Unit 1 experienced a turbine trip caused by high turbine vibration.
The resultant fast closure of the turbine control valves caused a reactor scram.
Control room operators felt and heard heavy vibrations in the control room.
Simultaneously with the vibration, Unit 1 scrammed.
Condenser demineralizer influent (CDI) peaked at 43 pmho/cm due to damaged main condenser tubes from two thrown turbine blades.
The operators responded to the event by entering the appropriate off-normal procedures.
There were no unexpected Engineered Safety Feature (ESF) actuations and no Emergency Core Cooling System (ECCS) initiations. The licensee made the proper 50.72 NRC four hour notification and initiated a scram investigation.
Safety systems responded, per design, to the turbine trip on high vibration.
The licensee did not detect any anomalies with the response of safety-related equipment.
The station concluded that primary containment integrity was maintained during the transient.
There were no indications of fuel damage caused by the transient.
The inspector concluded that the operators properly responded to the transient.
Plant safety systems responded per design with no apparent anomalies.
The licensee's root cause investigation was comprehensive and primarily focused on the cause of the thrown turbine blades.
See Section 7.2.1 for detail.
RADIOLOGICALCONTROLS 3.1 Inspection Activities PP&L's compliance with the radiological protection program was verified on a periodic basis.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
3.2 Inspection Findings Observations of radiological controls during maintenance activities and plant tours indicated that workers generally obeyed postings and Radiation Work Permit requirements.
3.2.1 Fuel Pool Filter Demineralizer Backwashing Causes Large Area Contamination On July 30, three elevations of the Unit 1 Reactor Building were contaminated during a Unit 1 fuel pool cooling (FPC) filter demineralizer (FD) backwash.
The licensee discovered the contamination after three decontamination personnel alarmed Personnel Contamination Monitors (PCMs) at the Unit 1 access and two operators alarmed PCMs at the 676'ontrol Structure access, all shortly after midnight on July 30.
The licensee postulated that during the backwash, air blew out of the overflow of the FPC backwash receiving tank (BWRT)
into a radwaste floor drain.
This air jet then forced residual contamination (dust) in the floor drain system back up into their respective areas.
Health Physics (HP) surveyed all rooms having drains on the same line as the FPC BWRT overflow floor drain and identified contamination on the 670', 749', and 762'levations.
Fifteen individuals that were in either the Unit 1 Reactor Building or Turbine Building during the backwash received whole body counts.
Four individuals showed signs of a small intake of radioactive materials with a maximum exposure of 1.64 maximum permissible concentration-hours (MPC-HR). The licensee formed an event review team to identify causal factors and to propose corrective actions.
The licensee identified the FPC FD design as one of two root causes.
A typical backwash blows down about 240 cubic feet of air, water, and resin to the FPC BWRT. An equivalent amount of air is displaced from the BWRT and must be exhausted out either the BWRT exhaust through a High Efficiency Particulate Air (HEPA) filter (OF211) or an overflow line.
During their investigation, the licensee found that the estimated air exhaust rate during a backwash exceeds the Zone 1 ventilation draw on the FPC BWRT, resulting in air blowing out the overflow line during each backwash.
During two separate events on August 12, 1991, the 749'levation was contaminated when two consecutive backwashes blew down the FPC BWRT and radwaste floor drain piping.
An operator error, and later, an equipment failure led to the inadvertent pressurization of an empty FD with instrument air, which resulted in larger than normal volumes of air blowing down to the FPC BWRT. However, during the July 30 event, the licensee could not identify any operator errors or equipment failures.
Thus, a more detailed review of the system design was undertaken.
Following a
comparison of the FPC and Reactor Water Cleanup (RWCU) FD designs, and a calculation of'air flows during a normal FPC FD backwash, the licensee discovered a FPC FD design deficiency.
The rate of discharge to the BWRT exceeds the capacity of the available head space in the tank and the room's ventilation exhaust rate.
The licensee also identified inadequate system indication during FD processing, the lack of a manual interrupt during the backwash cycle, the inability to exercise equipment, and poor equipment reliability as design deficiencies.
Although these design deficiencies did not contribute to this event, they will be evaluated ifpressurized backwashes continue to be used.
The licensee also identified partial blockage of BWRT exhaust HEPA filter (OF211), which diverted additional air to the FPC BWRT overflow during the FPC FD backwash, as a second root cause.
The original OF211 filter has remained since initial plant construction, despite two previous similar events which indicated the need to incorporate filter OF211 into a PM program.
On June 26, 1987, air blew out of the RWCU BWRT overflow line during air sparging of'the BWRT. The licensee changed out the HEPA exhaust filter on the RWCU BWRT and recommended the change out of OF211 in Technical Staff Memo (TSM) 88-0153.
However, the recommendation was inadvertently not implemented since no formal tracking existed for TSMs.
The licensee noted that ifthe 1987 event had been documented in a SOOR, any corrective actions identified would have been tracked and implemented.
On February 4, 1992, personnel received contamination while working on louvers on the supply duct to the FPC BWRT room, resulting in SOOR 1-92-041.
Along with other corrective actions, the licensee wrote Work Authorization (WA) S24346 to change filter OF211 and to check for clogging.
Radiation hot spot concerns delayed the filter change out, with the work postponed until the week of August 2-6, 1993.
The inspector noted that the licensee suspended all FPC FD backwashes during the ERT's investigation as a short term action.
For long term corrective actions, the licensee has agreed to establish a Preventive Maintenance (PM) requirement to change out filter OF211.
The licensee will also evaluate the FPC system design for enhancements, including whether gravity draining can be used during backwashes instead of a pressurized blowdown to the FPC BWRT. To limit the possibility for recurrence, the licensee has implemented compensatory actions for future FPC FD backwashes.
These actions include plugging the radwaste floor drain under the FPC BWRT overflow line, while leaving the room floor drain open for flooding contingencies.
Prior to a backwash, an additional temporary ventilation exhaust willbe established through a HEPA filter at the FPC BWRT entrance.
HP will also verify that personnel are not in the affected areas on 670'nd 749'nd then post the areas to preclude entry.
After the backwash, the areas willbe checked for contamination, and reposted based on contamination level, and the temporary ventilation system will be secured.
The inspector has noted that the licensee has implemented these compensatory actions for recent FPC FD backwashes with good success.
Thus, the inspector concluded that the licensee's root cause identification and corrective actions were appropriate and has no further question.
MAINTENANCE/SURVEILLANCE 4.1 Maintenance and Surveillance Inspection Activity On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that specific programmatic elements described below were being met.
Details of this review are documented in the following sections.
4.2 Maintenance Observations The inspector observed and/or reviewed selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered, as applicable, during this review:
Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and quality control hold points were established where required; functional testing was performed prior to declaring the involved component(s) operable; activities were accomplished by qualified personnel; radiological controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to service.
These observations and/or reviews included:
WA 25041, Low Pressure "C" Rotor Disassembly and Inspection, dated July 14 to August 13.
WA 36007, Replace Division II Suppression Pool (SPOTMOS) RTDs, dated July 26, 1993.
WA 31942, "B" Core Spray Motor Annual Inspection, dated July 29.
WA 30919, Replace Defective Torque Switch on Core Spray Loop "B" Suction Valve HV152F001B, dated August 3.
4.3 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, ifapplicable to the specific test, were met:
the test conformed to Technical Specification requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved procedure; test instrumentation was calibrated; Limiting Conditions for Operations were met; test data was accurate and complete; removal and
restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
These observations and/or reviews included:
SO-158-003, Semi-annual RPS Electrical Power Monitoring Assemblies (FPA)
Channel Functional Test, dated July 15, 1993.
SM-024-002D, 18 Month Inspection "D" Diesel Generator, dated July 26 - August 13.
SI-249-204, Monthly Functional Test of Reactor Vessel Pressure High (RHR Cut-in Permissive) Channels, dated July 28.
4.4 Inspection Findings The inspector reviewed the listed maintenance and surveillance activities.
The review noted that work was properly released before its commencement; that systems and components were properly tested before being returned to service and that surveillance and maintenance
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activities were conducted properly by qualified personnel.
Where questionable issues arose, the inspector verified that the licensee took the appropriate action before system/component operability was declared.
Except as noted below, the inspectors had no further questions on the listed activities.
4.4.1
"D" Emergency Diesel Generator Overhaul During the period, the licensee began the five year overhaul of the "D" emergency diesel generator.
SM-024-002, 18 Month Emergency Diesel Engine Inspection, requires a visual inspection of the cylinder liners for scuffing.
The licensee's inspection identified some cylinder liners that had scoring and scratches.
PP&L performed a porosity test on all the cylinders based on the results of the visual inspection.
Six cylinder liners did not satisfy the porosity acceptance criteria by a small margin.
Of these, three cylinder liners were scored in various locations around their entire circumference and had scratches the length of the piston travel.
Nuclear System Engineering (NSE) documented this on Nonconformance Report (NCR)93-080.
The porosity test indicated a decrease in porosity which can be detrimental to lubrication.
Lubrication problems can lead to engine degradation.
The licensee subsequently removed the pistons and cylinder liners for the six affected cylinders.
Several piston rings were scratched.
PP&L metallurgists analyzed carbon residue taken from the piston and piston rings.
The analysis results showed minute traces of aluminum oxide (sand blast grit). The licensee suspected this residual aluminum oxide was
left over from the 1990 sandblast grit intrusion into the "B" & "D" EDGs during maintenance activities.
The 1990 sand blast intrusion event resulted in EDG damage.
This occurrence was documented in NRC Inspection Reports 50-387/90-15 and 50-387/90-20.
The licensee determined that the scratches and areas of low porosity on the cylinder liners were unacceptable and would require liner repair or replacement prior to returning the EDG to service.
The licensee determined operability of the "D" diesel was not impaired prior to discovery of the anomalies as evidenced by the successful demonstration of the diesel generator operability during routine surveillance testing.
The licensee also believed the observed degradations were not rapid in nature.
A Chromium Corporation representative also inspected the chromium lined cylinder liner and considered the cylinder liners damage to be minimal.
Routine monthly lube oil samples did not indicate abnormal amounts of aluminum oxide or chromium.
The licensee concluded that the residual aluminum oxide caused the observed cylinder liner and piston ring scratches.
The inspector concurred with their root cause evaluation.
Nuclear System Engineering dispositioned the NCR to correct the condition.
PP&L installed refurbished cylinder liners in the six affected cylinders.
Since the identified residue contained aluminum oxide, the licensee decided to remove six additional pistons to facilitate residue cleaning.
The six additional pistons were chosen because of the existence of some scoring.
However, it was well within the acceptance criteria.
The licensee analyzed residue from various other locations Jube oil filter, air start header, air intake header, turbocharger, and lube oil sump) within the engine.
No additional aluminum oxide was detected at any of these locations.
The licensee ruled out intrusion from other sources and concluded that the aluminum oxide was residual from the 1990 event.
A total of 12 pistons were cleaned with each having their piston rings replaced.
The inspector agreed with the licensee's operability assessment.
The inspector also questioned the licensee on the "B" engine since it was subject to the same aluminum oxide intrusion in 1990.
The licensee stated that the "B" EDG cylinder liners were inspected in February 1993 with satisfactory results.
However, they are evaluating scheduling the "B" EDG five year overhaul for January 1994 instead of mid-1994 as a prudency measure, The inspector noted that Maintenance and NSE effectively used the NCR program to thoroughly document and resolve the noted discrepancy.
The inspector also directly inspected the cylinder liners and agreed with the licensee's assessment that the cylinder liner damage was minimal. The licensee's EDG inspection procedures detected the problem before any significant degradation occurred.
Thus, the inspector concluded the licensee actions were appropriate and conservative in nature and had no further question.
EMERGENCY PREPAREDNESS 5.1 Inspection Activity The inspector reviewed licensee event notifications and reporting requirements for events that could have required entry into the emergency plan.
5.2 Inspection Findings No events were identified that required emergency plan entry.
6.
SECURITY 6.1 Inspection Activity PP&L's implementation of the physical security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
6.2 Inspection Findings
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The inspector reviewed access and egress controls throughout the period.
These controls were acceptable.
7.
ENGINEERING/TECHNICALSUPPORT 7.1 Inspection Activity The inspector periodically reviewed engineering and technical support activities during this inspection period.
The on-site Nuclear Systems Engineering (NSE) organization, along with Nuclear Technology in Allentown, provided engineering resolution for problems during the inspection period.
NSE generally addressed the short term resolution of engineering problems; and interfaced with the Nuclear Modifications organization to schedule modifications and design changes, as appropriate, to provide long term corrective action.
The inspector verified that problem resolutions were thorough and directed at preventing recurrence.
In addition, the inspector reviewed short term actions to ensure that they provided reasonable assurance that safe operation could be maintaine.2 Inspection Findings 7.2.1 Unit 1 Turbine Blading Failure Background In 1985, a General Electric (GE) three casing turbine generator torsional failure incident occurred at the Taiwanese Maanshan Unit 1 plant.
As a result, on September 8, 1987, GE issued Technical Information Letter (TIL-1012-2), Electrical System Variations on Turbine Generator Torsional Response.
Prior to the Maanshan event, GE believed that high torsional vibration modes would not result in high rotor response.
However, in TIL-1012-2, GE revised its earlier conclusions and stated that torsional vibrations could result in damage to certain turbine-generator components.
Certain electrical system disturbances were considered to be potential torsional vibration initiators and they were (1) negative sequence current caused by untransposed line loads, unbalanced loads and unbalanced faults, and (2) other electric faults, such as, near-in single-phase faults and two-phase faults.
In TIL-1012-2, GE recommended conducting ultrasonic testing on the last stage bucket dovetails (L-0) and nondestructive evaluation (NDE) of the alternator shafts.
GE also recommended conducting torsional resonant frequency tests to determine ifspecific natural frequencies existed in a given turbine generator that were near 120 Hz.
GE considered the potential for torsional vibration at this frequency to be more likely since it was a natural multiple of the generator output frequency (60 Hz).
The rotating mass of the turbine vibrates laterally, axially and torsionally.
The vibration of interest is torsional (twisting along its axis).
The particular mass and geometry of the rotating element (turbine-generator assembly) define its natural frequency.
There are many natural frequencies called modes.
Each vibrational mode is characterized by a frequency and a mode shape.
The mode shape indicates the level of response which would occur from external excitation of the shaft at a given frequency.
Each torsional mode is a result of the combination of individual component natural frequencies in the turbine-generator assembly.
The licensee evaluated their resonant frequency in 1987 and found it was outside 120 Hz, and thus, elected not to implement the GE recommended torsional testing from the TIL.
However, they performed NDE on the Alterex in a 1988 Unit 1 refueling outage.
No unusual indications were identified.
Licensee Investigation Based on the felt vibration and conductivity excursion, the licensee suspected turbine damage during the July 12 scram.
As a result, the licensee formed a detailed inspection plan and a root cause team to evaluate turbine damage.
Their initial condenser inspection revealed 50-100 sheared or perforated condenser tubes.
The turbine vendor, GE, assisted the licensee with turbine damage assessment and root cause determination.
A consulting firm (MPR
Associates)
was also contracted to provide assistance during the investigation and root cause determination.
The "C" low pressure (LP-C) rotor was disassembled and the licensee found that two L-1 row buckets (blades) were thrown on the LP-C rotor turbine end.
The licensee, with GE assistance, determined that on the L-1 rotating row of the LP-C turbine end, blades ¹11 and ¹89 separated from their fingers at the upper pin holes or attachment points to the turbine rotor.
There was extensive consequential damage to the other'ortions of the turbine resulting from the two thrown buckets.
Disassembly of the LP-C rotor L-1 blade row on both ends revealed approximately 32 completely broken fingers and numerous other fingers with cracks.
Each bucket (blade) has six fingers with six holes each that hold the bucket to the rotor by six staked pins.
The licensee found that all of the broken/cracked fingers were at the top holes of a three row in a two pins per row configuration.
A high percentage of the broken fingers showed they had been cracked for some time. A magnetic particle examination was also performed on the LP-C rotor L-1 and L-0 stages at both governor and generator ends.
Based on this, the licensee determined that no rotor damage occurred.
The licensee also visually inspected the LP-B rotor L-1 buckets (without detaching any of the buckets) and determined no observable cracks existed.
A liftcheck of the LP-B L-1 buckets indicated all buckets were seated properly.
Root Cause Determination The licensee concluded, in an interim report dated August 12, that the root cause of the turbine blade failure was high cycle fatigue.
This conclusion endorsed a GE position espoused between GE and the licensee during a July 22 meeting.
The licensee believes that this high cycle fatigue may have been due to torsional vibration caused by negative phase sequence current (NPSC).
This NPSC may have provided a stimulus at the generator that acted in resonance with a natural torsional frequency of the rotor.
According to the interim report which endorsed the GE failure analysis, the 20 torsional vibration mode shape for the Susquehanna turbine-generator rotor system peaked at 120.4.
This revised a 1987 GE calculation that showed the frequency of the 20'ibrational mode shape peaked at 119.1 Hz.
Both analyses showed the L-1 stage on the LP-C turbine end created the highest blade response for the installed monobloc rotor configuration.
The interim report also concluded that NPSC was the excitation stimulus that caused the resonant torsional vibration.
The inherent load unbalance that exists between the three phases of the generator creates a current flow in the generator stator which is opposite to the direction of the main current flow. This "negative phase sequence current" in the stator interacts with the rotating electrical field to create an alternating torque at a frequency of 120 Hz which is twice system operating frequency (60 Hz). This torque "bumps" the shaft in the torsional direction.
The torque propagates down the turbine shaft and its energy is
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preferential imparted (based on vibrational mode shape) to certain turbine rotating
components (i.e., LP-C L-1 stage turbine buckets).
The interim report also indicated that at a 1800 rpm shaft speed, negative phase sequence current can induce a torque that is close to the natural frequency of the 20~ torsional mode of the shaft.
This results in an amplification of turbine blade vibration.
Susquehanna Unit 1 output frequency typically varies between 59.98 Hz and 60.03 Hz.
These small variations can result in a phase loading unbalance that results in negative phase sequence currents.
The nominal magnitude of the negative phase sequence currents seen at Susquehanna is 1.8% which is within the expected range of 1%-2%.
The root cause team's evaluation concluded that the normal Unit 1 negative phase sequence currents were of sufficient magnitude to stress the L-1 blade dovetails to their ultimate failure.
After examination of the GE calculations of L-1 stage blade stress due to torsional resonance and the physical examination of the blades and fingers, the root cause team concluded with a high degree of probability that the root cause of turbine blading or bucket failure was a high cycle fatigue from resonant torsional vibration.
The team found that the calculated natural frequency of the turbine-generator rotors at 120.4 Hz and the existence of negative phase sequence currents sufficient to drive high cycle fatigue cracks to cause resonant torsional vibration.
The team also identified six other phenomenon that could lead to high cycle fatigue.
The team evaluated these phenomenon and preliminarily ruled them out as contributors to the turbine failure.
The six that were essentially ruled out were as follows:
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Flow induced vibration Harmonic excitation (other than from torsional vibration)
Water induction Material strength determination/corrosion fatigue Manufacturing and assembly issues Material issues The interim report conclusions are based on the examination of evidence to date.
Some additional analysis remains to conclusively rule out these other phenomenon.
Corrective Actions General Electric removed the old buckets and installed new buckets on both ends of L-1 row and on the L-0 row of the C L-P turbine.
Repairs were also made to the 12 and 13 stage diaphragms.
The LP condenser was cleaned and the condenser tubes repaired.
The licensee removed and plugged 11 severely damaged tube sections in the "A" tube bundle.
The main condenser hotwell was inspected and cleaned of debri The licensee has installed an inertial mass ring to detune the Unit 1 turbine rotor away from the 20 mode shape peak frequency of 120 Hz. The addition of the inertia ring is predicted to lower the natural torsional frequency of the rotor.
These predictions will be evaluated during torsional testing on startup.
The predicted frequency peak following the addition of the inertia ring is 117.8 Hz.
Since available analytical data suggests that the Unit 2 turbine is susceptible to this phenomenon, the licensee willalso perform the torsional testing on Unit 2.
PP&L is evaluating when to schedule this test.
NSE is currently evaluating the need for additional inspections of the LP-B during the September 1993 Unit 1 refueling outage.
The inspection being considered will require the removal of buckets from both ends of the L-1 and L-0 blade rows for the LP-B rotor.
NDE willbe performed on the bucket fingers to detect cracking.
The licensee is also re-evaluating their entire turbine inspection program.
Certain improvements and enhancements are anticipated as a result of this event.
NRC Findings and Conclusions At various points of turbine disassembly and condenser inspection, the inspector observed the damaged turbine and components.
Cracked fingers were visually examined, as well as, fracture surfaces from damaged buckets.
These fracture surfaces showed signs of high cycle fatigue failure.
Microscopic examination is necessary to confirm the visual observations.
The inspector agreed with the licensee's root cause determination that high cycle fatigue caused bucket failure.
Further, the addition of an inertia ring and subsequent testing for the resultant detuning of the turbine would appear to correct the most likely cause of the failure.
However, the specific initiator is still under consideration by the NRC.
There is a great deal of uncertainty in natural frequency calculations provided by GE and there is little physical evidence to support the existence of NPSC above normal levels.
The licensee's conclusion that normal NPSC were sufficient to cause blade failure is plausible, however, it is not strongly supported by the facts.
Thus, the NRC acceptance of the licensee's root cause will remain unresolved pending the licensee final root cause evaluation.
(UNR 50-387/93-11-01)
8.
SAFETY ASSESSMENT/QUALITY VERIFICATION 8.1 Open Items 8.1.1 (Closed) NV4 50-387/92-02-02(Common),
Inadequate Investigation of Hydrogen Ignition Precursor Event On January 18, 1992, hydrogen in an open ended section of offgas pipe ignited and detonated when a worker began a planned grinding activity. A potential precursor event was identified on January 16.
However, the licensee's investigation did not identify a leaky boundary valve that was allowing hydrogen to accumulate in an open ended offgas pipe.
This resulted in an apparent violation.
The licensee responded to this violation on March 27, 1992 and agreed to take certain actions to prevent recurrence.
The licensee performed the following corrective actions:
1.
The operators involved were counseled on the importance of proper communication.
2.
The incident was reviewed with station personnel as part of the Unit 1 (Ul) 6 refueling outage (6RIO) pre-briefing/training conducted by Station Management.
~
~
3.
Information on the event was incorporated into General Employee Training and Retraining courses which are required annually for employee access to SSES.
4.
Hot Box Training 92-13 was completed for all Operations shift personnel to review the January 16, 1992 event and reinforce management's communication expectations.
The inspector found the listed corrective actions to be responsive to this violation.
In addition, the inspector sampled these actions to verify their completion.
The inspector noted that the Ul 6RIO management pre-brief contained a description of the incident, its consequences and the lessons learned from the event.
In addition, lesson plans for General Employee Training and Retraining were revised to include the hazards involved with working with systems that contain hydrogen gas.
Operators reviewed Hot Box Training 92-13 which clearly identified the need for improved communication and complete investigations of anomalous indications.
These actions appeared to provide reasonable assurance that this violation will not recur.
Based on the above, this item is closed.
8.1.2 (Closed) NV4 50-387/92-02-03 (Common), Improper Work Authorization (WA)
Closeout On January 18, hydrogen in an open ended section of offgas pipe ignited and detonated when a worker began a planned grinding activity. An earlier repair activity was found to be incomplete.
Workers signed offa WA for repair of valve HV-16907 as complete, without
14 repairing its leaky seat.
This valve was the only blocking boundary and its leaky seat allowed hydrogen to buildup to explosive levels.
This was a violation.
The licensee responded to this violation on March 27, 1992 and agreed to take certain actions to prevent recurrence.
The licensee performed the following corrective actions:
1)
AD-QA-502 was revised to require a foreman review, prior to closeout of WA packages, for completeness and technical accuracy. Ifopen actions remain or are identified during this review, a new WA is initiated to track the action.
2)
Maintenance supervisory personnel were trained on the action required by 1) above.
3)
A Maintenance Department Self Assessment Program was instituted to identify improvement opportunities for meeting maintenance objectives (observations of WA work instructions is one of the self assessment categories).
The inspector reviewed the licensee's corrective actions and found them to be responsive to this violation. The inspector noted that AD-QA-502, Work Authorization System, Revision-19, Step 6.8.2 requires the foreman-in-charge to review the work package for completion.
This step also requires the initiation of a new WA ifthe action taken did not correct the problem defined on the original WA. In addition, thirteen second line supervisors completed the aforementioned training on June 23, 1992.
The Nuclear Quality Assurance (NQA)
surveillance group audited this training in Quality Assurance Surveillance Record (QASR)92-079.
NQA noted that the first line supervisors did not attend the requested training and questioned maintenance on this action.
Various foremen were contacted and NQA determined that the goals of the training were achieved by foremen briefs, individualized training, or by retraining review responsibilities.
NQA determined that acceptable guidance was given on this new requirement.
After careful consideration of the additional guidance, the inspector concurred with NQA's assessment.
Thus, these actions appeared to provide reasonable assurance that this violation will not recur.
Based on the above, this item is closed.
8.2 Unavailability of Temperature Indication During Cold Shutdown On July 15, 1993, during the current forced outage, the licensee performed Technical Specification required surveillance SO-158-003, Semi-Annual Reactor Protection System (RPS) Electrical Power Monitoring Assemblies Channel Functional Test.
The unit was in cold shutdown following a scram on July 12 due to a main turbine high vibration trip.
During the surveillance, operators secured shutdown cooling (SDC) and reactor water cleanup (RWCU) per SO-158-003.
Securing these systems resulted in a loss of temperature indication.
Per SO-158-003, the Residual Heat Removal (RHR) and Reactor Water Cleanup (RWCU) systems were taken out-of-service to prevent their unintentional isolation during the surveillance.
The "A" Loop of Reactor Recirculation (Recirc) had been previously out-of-service for seal replacement and the "B" Loop of Recirc was out-of-service since the "B"
Loop of RHR had been in use.
This surveillance is required to be performed each time the plant is in cold shutdown for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless it had been performed within the previous six months.
The inspector noted this anomaly during a control room walkdown and questioned the operators regarding their lack of temperature indication during the surveillance.
The inspector noted that operators were aware no temperature indication existed.
To compensate, the operators ensured temperature was low in the allowable band prior to securing shutdown cooling.
According to the operators, the loss of all temperature indication was noted and discussed at the pre-evolution brief (tail board).
The surveillance procedure did not ensure that a means of temperature indication remained available or address the potential loss of temperature indications.
The temperature, prior to securing shutdown cooling, was 106.5'F.
Shutdown cooling was restored in approximately 51 minutes.
Temperature increased to 131'F during the time shutdown cooling was secured.
No temperature limits were exceeded.
The inspector noted that the surveillance was performed at a time when significant decay heat was present.
Apparently, the scheduling of the surveillance did not fully consider the ramifications of a loss of SDC and other shutdown risk factors during a period of significant decay heat and without temperature indication.
During planned refueling outages, this surveillance has been historically performed after the midpoint of the refueling outage.
During this time, decay heat levels are low and a loss of shutdown cooling would have little impact since the fuel is offloaded to the spent fuel pool.
Also, due to the turbine damage in the current forced outage, it was apparent that the plant would be in cold shutdown longer than seven days.
This would allow performing the surveillance during a period of lower decay heat load.
During a routine control room observation, the licensee's Nuclear Safety Assessment Group (NSAG), also independently identified that the operators secured shutdown cooling without temperature indication for SO-158-003.
They were also concerned with the lack of temperature indication during a period when SDC was out-of-service.
As a result, they began their investigation following their identification of this event.
Based on discussions with NSAG, the inspector noted that their investigation was going to describe the event and its attendant safety concerns, including their assessment of potential consequences.
NSAG's corrective action recommendations would be based on their independent conclusions.
The inspector concluded that the licensee's planning and performance of the surveillance without a detailed plan to minimize shutdown risk was of concern.
Specifically, the inspector noted that shutdown cooling was secured with a significant amount of decay heat present and without temperature indication available.
Operators were aware that temperature indication would be lost during the surveillance and they expected a given heat-up rate during the evolution.
However, no pre-planned contingency measures existed to compensate for a potential extended loss of SDC.
Any problems with the restoration of SDC would have been exacerbated by the high decay heat load, such that temperature could have increased to 200'F in a matter of a few hours which would have resulted in an unplanned mode chang In addition, the inspector determined the surveillance procedure did not adequately identify or address these contingency measures.
The inspector also noted that, even though the operators were briefed, the pre-planning of the surveillance did not overtly consider a number of shutdown risk factors.
These included, but were not limited to, the scheduling of the surveillance during startup or the potential consideration of a bypass to prevent RWCU or RHR containment isolation valve closure to preserve temperature indication.
Other factors to be considered included the availability of injection systems, and also, the ability to promptly reestablish primary and/or secondary containment integrity. The inspector considered NSAG's independent identification of the problem and their initiative to prepare a detailed report with recommendations a significant strength.
The final NSAG report had not been issued at the conclusion of the inspection period.
The licensee evaluation of the event was still in progress at the end of the report period.
The licensee's management of shutdown risk for this forced outage will remain unresolved pending further NRC review of their corrective actions, (UNR 50-387/93-11-02(Common))
9.
MANAGEMENTAND EXITMEETINGS 9.1 Resident Exit and Periodic Meetings The inspector discussed the findings of this inspection with station management throughout and at the conclusion of the inspection period.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to 10 CFR 2.790 restrictions.
9.2 Inspections Conducted By Region Based Inspectors Date Insg~i n
~Re ~rt N>
R~eortin
~ln pe~et r 07/12 - 07/16/93 Environmental Monitoring 08/09 - 08/13/93 Emergency Preparedness 93-12 93-14 J. Jang J. Lusher