IR 05000107/2002008
| ML17139D022 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna, 05000107  |
| Issue date: | 03/08/1985 |
| From: | Jacobs R, Plisco L, Stosnider J, Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17139D021 | List: |
| References | |
| 50-387-85-01, 50-387-85-1, 50-388-85-01, 50-388-85-1, NUDOCS 8503280737 | |
| Download: ML17139D022 (32) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-387/85-01 50-388/85-01 Docket Nos.
50-387 CAT C 50-388 CAT B2 License Nos.
NPF-14 NPF-22 Licensee:
Penns lvania Power and Li ht Com an 2 North Ninth Street Allentown Penn s 1 vani a 18101 Facility Name:
Sus uehanna Steam Electric Station Inspection At:
Salem Townshi Penns lvania Inspection Conduct d:
anuar 7 - Februar
1985 Inspectors:
H. J cobs, Senior Resident Inspector date Approved By:
R.
Pl co Resident Inspector date J c Strosnider, Chief Reactor Projects date ection 1C, DRP k
Ins ection Summar
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f plant operations, maintenance and surveillance, licensee events, open items, startup testing, Unit 2 reactor scram, and Unit 1 drywell leakage.
Results:
MSIV leakage control system walkdown identified procedural and draw-ing deficiencies (Detail 2.3);
containment H2/02 analyzers have not proven re-liable (Detail 4.2);
licensee calculations of Unit 1 drywell leakage are con-servative (Detail 8.0).
No violations were identified.
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OETAILS 1.0 Followu on Previous Ins ection Items Closed Ins ector Followu Item 387/84-34-02
- Post Tri Review Does Not Check RPS Res onse Times In Inspection Report 50-387/84-34, the inspector noted that the pro-cedure for conducting post trip (scram)
reviews did not include eval-uation of RPS actuation and recirculation pump times.
The inspector reviewed Administrative Directive AD-gA-415, "Post Re-actor Transient/Scram/Shutdown Evaluation" Revision 1 dated January 16, 1985.
This procedure has been revised to specify taking data on RPS actuation and recirculation pump trip times.
The procedure also requires the STA to evaluate rod scram timing data from GETARs to ensure the scram times are less than the technical specification limits.
1.2 Closed Ins ector Followu Item 387/82-32-02
- Individual in Vital Area with Unauthorized Securit Bad e
1.3 In 1982, an individual was found in a vital area with an unauthorized security badge.
The licensee's security badge system has been re-vised since this incident and all authorized individuals have been reissued security badges.
Closed Ins ector Followu Item 387/84-07-03
- Licensee Event Re ort on HPCI Ino erabilit was Inade uate In Inspection Report 50-387/84-07, the inspector determined that Licensee Event Report ( LER)84-009 concerning an incident involving HPCI inoperability did not contain all the
CFR 50.73 LER content requirements.
1.4 The quality of LERs submitted to the NRC in 1984 is much improved over previous years.
The inspectors have reviewed all LERS submitted since LER 84-009.
With one exception, these LERs have fully documen-ted the occurrence and met the content requirements of 10 CFR 50.73.
The one exception was Unit 2 LER 84-010 concerning the HPCI startup suction strainer which was reviewed in Inspection Report 50-388/
84-33.
The licensee submitted a
supplement to LER 84-010 on January ll, 1985, which will be reviewed under unresolved item 388/84-33-02.
Closed Ins ector Followu Item 387/83-29-05
- Radioactive S ill in Turbine Bui ldin In January 1984, a spill of about 10,000 gallons of water occurred while attempting to drain the Unit 1 reactor well to the Refueling Water Storage Tank (RWST).
Licensee corrective actions involved re-view and revision of the affected procedures and training of opera-tions personne The inspector reviewed procedures OP-037-001
"Demineralized, Conden-sate and Refueling Water Transfer System",
Revision 2 and and OP-135-001
"Unit
Fuel Pool Cooling and Cleanup System" Revision 2.
The inspector compared the procedural lineups with the affected P&IDs and verified that lineups isolated interfacing systems from the flowpath to assure that the reactor well water would drain to the proper loca-tion.
OP-235-001,
"Unit 2 Fuel Pool Cooling and Cleanup System" has also been revised.
The inspector also reviewed attendance sheets for operator training conducted on this incident.
Closed Violation 387/84-07-01
- Individual Entered a Hi h
Radiation Area Without a Dose Rate Instrument In March 1984, the Unit
Reactor Building Nuclear Plant Operator entered the Unit 1 fuel pool cooling pump and heat exchanger room, a
posted High Radiation area, without using a dose rate instrument as required by the Radiation Work Permit.
The affected individual was counseled and required to receive addi-tional training in Practical Health Physics and Health Physics re-training.
The inspector verified that the individual has received the above training.
The licensee is also reemphasizing radiation area entry requirements during annual Health Physics retraining of all personnel.
Closed Unresolved Item 387/82-42-01:
Use of Handwritten Procedures Several station procedures were found to be handwritten instead of issued with an Advanced Test Management System (ATMS)
generated copy.
The inspector reviewed AD-gA-101,
"Procedure Program",
Revision 9.
Section 6.8 of this procedure has been revised to permit usage of handwritten procedures on an
'as needed'asis, for up to 60 days.
Additionally, the inspector verified that the handwritten procedures identified in Inspection Report 50-387/82-42 had either been deleted or reissued by ATMS.
Closed Violation 387/84-07-05
Im ro er Service Water Radiation Monitor Set oint In March 1984, the inspector determined that the alarm setpoint for the Unit
Service Water Radiation Monitor was not set to detect radioactivity within the limits specified in Technical Specification 3. 11. 1. 1.
The cause of the incorrect setting was due to the calibra-tion procedure not accounting for varying background radiation levels and a high background at the detecto g Ip
~~
In response to this violation, the licensee declared the monitor in-operable and took chemistry samples until the monitor was recalibra-ted.
The Unit
and 2. service water calibration procedures, SC-11-102 for Unit
and SC-24-102 for Unit 2, were revised to properly account for the background levels and the monitors were recalibrated.
A plant modification was implemented on both Units
and 2 to add additional shielding around the monitor to reduce backgound radiation levels.
The inspector reviewed SC-11-102, Revision 2 dated October 10, 1984, SC-24-102, Revision 1 dated October 31, 1984, and the current cali-bration results for the Unit
and 2 monitors.
The licensee conser-vatively assumes all activity is due to CS-137 and the high and low alarm setpoints are set to detect activity at the maximum permissible concentration (MPC) of CS-137 for release to unrestricted areas.
The procedures specify the following for alarm point settings:
If background is less than one-half MPC, then the low (down-scale)
alarm is set at one-half background and the high alarm is set at one-half background plus MPC. If background is greater than one-half MPC, the downscale alarm is set at background minus one-half MPC and the high alarm is set at background plus one-half MPC.
The difference between the downscale and high alarm setpoints is MPC in either case which meets the requirements of Technical Specifica-tion 3.11.1.1.
The inspector verified that the current monitor setpoints were cor-rectly calculated and verified that background levels had been re-duced by the addition of shielding.
The Unit 1 monitor background level is now 200 counts per second (cps)
and the Unit 2 monitor is
cps.
The procedure also contains a caution to notify supervision if background levels significantly increase.
2.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room area daily to verify proper manning, access control, adherence to approved procedures, and com-pliance with LCOs.
Instrumentation and recorder traces were observed and the status of control room annunciators were reviewed.
Nuclear instrument panels and other reactor protective systems were examined.
Effluent monitors were reviewed for indiations of releases.
Panel indications for onsite/offsite emergency power sources were examined for automatic operability., During entry to and egress from the pro-tected area, the inspector observed access control, security boundary integrity, search activities, escorting badging, and availability of radiation monitoring equipmen l e
The inspector reviewed shift supervisor, plant control operator, and nuclear plant operator logs covering the entire inspection period.
Sampling reviews were made of tagging requests, night orders, the bypass log, incident reports, and gA nonconformance reports.
The inspector also observed several shift turnovers during the period.
No unacceptable conditions were identified.
2.2 Station Tours The inspector toured accessible areas of the plant including the con-trol room, relay rooms, switchgear rooms, penetration areas, reactor and turbine buildings, diesel generator building, plant perimeter and containment.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to pro-cedures, radiological controls and conditions, housekeeping, secur-ity, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
No unacceptable conditions were identified.
2.3 ESF S stem Walkdown On February 6,
1985, the inspector independently verified the opera-bilityy of the Unit
Main Steam Isolation Valve Leakage Control System (MSIV-LCS) by performing a complete walkdown of the accessible portions of the system.
The engineered safety feature system status verification included the following:
Confirmation that the system check-off list and operating pro-cedure are consistent with the plant drawings and as-built con-figuration, Identification of equipment conditions and items that might de-grade performance, Inspection of breaker and instrumentation cabinet interiors, Verification of properly valved in and functioning instrumenta-tion, Verification that valves and breakers were properly aligned, and appropriate valves were locked.
The following references were utilized during this review:
Technical Specification 3.6. 1.4 FSAR Sections 6.7 and Bechtel Drawing M-139, Revision 7, Unit 1 MSIV-LCS Operating Procedure OP-184-001, Revision 2,
Main Steam System GE Elementary Drawing, Ml-E32-18, MSIV Leakage Control Bechtel Isometric, GBB-134-2, MSIV Leakage Control Bechtel Schematics, E-189, Sheets 1-4, MSIV-LCS Surveillance Procedure, S0-184-004, Revision 1,
Monthly MSIV Leakage Control System Blower and Heater Operability Test S0-184-002, Revision 2,
MSIV Leakage Control 18-Month System Functional Test The inspector determined that the system was properly aligned in accordance with the operating procedure and equipment conditions in-dicated the components were well maintained.
The following items were identified:
Several procedural deficiencies were identified in the 18 month logic functional test SO-184-002.
The inspector discussed the items with the responsible engineers and found that the Tech-nical Staff is assuming responsibility for the procedure, and it has been rewritten in a
new format; therefore, the operations surveillance test will no longer be utilized.
The previous revision of the procedure used during the actual performance of the test was correct.
FSAR Section 6.7'. 1. 1 states that a pressure sensor is used to interlock the outboard blower suction valves to prevent valve actuation when main steam line pressure is greater than 0.5 psig.
Inspector review of the setpoint index and surveillance calibration procedures found that sensor setpoint is actually 1.0 psig.
The FSAR needs revision to correctly reflect the as-built configuration.
General Electric Elementary Ml-E32-18 sheet 5 incorrectly indi-cates that the power supply for the B and F inboard system logic trains is lY216 breaker No.
6 (Division I), but actually the power supply is 1Y226 breaker No.
6 (Division II).
The drawing requires correction to correctly reflect the as-built configura-tion.
The operating procedures and surveillance procedures cor-rectly reflect the power supplie During the system wal kdown the inspector noted several bypass tags hanging from the blower dilution flow elements.
Bypass 82-84-05 removed the flow elements FE-13954 and FE-13959 on the blower dilution flow lines to provide the minimum required flow ratio of five to one.
Bypass 82-83-17 opened the high side tap of the of the flow transmitters to atmosphere because the flow orifices were removed.
The installed flow elements had restric-ted flow such that the 5/1 dilution flow to bleed off flow was not met.
Review of the bypass log found that the flow elements will be permanently removed, and the flow instruments redesig-nated as pressure instruments, in modification PMR 83-112 which will be performed during the first refueling outage (February 9, 1985).
The inspector reviewed the proposed modification package.
The package stated incorrectly that the modification did not require an FSAR change.
The dilution flow indicators are de-scribed in the FSAR as differential pressure sensors (FSAR Sec-tion 6.7.2. 1) and they provide various alarm and interlock func-tions.
Additionally, the FSAR figure indicates the flow ele-ments and flow transmitters.
The FSAR does actually require re-vision.
During a control room tour the inspector noted that the main steam line high leakage interlock timer settings were inconsis-tent between the two units.
The Unit 1 timers were set at three minutes and the Unit 2 timers were set at five minutes.
The timer is used to secure the system if excessive bleed flow is detected upon system initiation, indicating an open MSIV.
Re-view of Unit 2 surveillance procedure SO-284-002 found that the procedure had been been revised by Procedure Change Approval Form (PCAF) 2-84-1406, and approved at PORC meeting 84-262 for a permanent change, to alter the bypass timer setting from three to five minutes.
The PCAF indicated properly that the change altered the intent of the original procedure and constituted a
CFR 50.59 change.
The safety evaluation stated that during Unit 2 preoperational testing approximately four and one-half minutes was required for the blower to stabilize, therefore the system would trip when the three minute timer timed out.
There-fore, to increase the system reliability the timer was set to five minutes, the maximum allowed by the motor driven timer.
An Engineering Work Request (EMR) was initiated to verify that the increased timer setting would not affect the offsite dose calcu-lations.
A Request for Modification (RFM)
has been submitted for both units, based on a
GE recommendation, to replace the
5 minute timers with 0 15 minute timers and change the setpoint to
minutes.
This change was based on preoperational tests per-formed at Grand Gulf.
The modification is currently planned for the next refueling outag 'L If'
The inspector questioned the licensee concerning why the Unit
timers had not been changed due to the questions of reliability raised on Unit 2.
The licensee stated that the Unit
system had functioned properly during its preoperational testing, and it was decided that Unit 1 would remain at 3 minutes until mod-ified to the fifteen minute timer.
The surveillance test will be performed during the upcoming refueling outage and should demonstrate that the three minute timer is adequate to allow proper system operation.
The operating procedure, OP-184-001, Main Steam System, included several deficiencies.
Several of the procedural steps identi-fied system components whose nameplate did not correspond to the procedure description.
For example, the procedure identified Inboard System Air Blower 1K208; but, on control room panel 1C644 it is labeled Inboard Air Blower E32-C001.
There were additional human factor deficiencies on the control room panels, such as the majority of the indications were not labeled with the instrument identification number, and the labels again did not match the procedure nomenclature.
The inspector also noted that the test switches used for heater and blower testing were not included in the system alignment check-off list.
Discuss-ions with operations personnel found that the switches should be included in the procedure.
The licensee will revise the proced-ure to include the test switches.
The items identified above are unresolved pending review of the licensee's corrective action.
(387/85-01-01)
In addition to the walkdown, the inspector witnessed the performance of the monthly operability surveillance, S0-184-004, on January 9,
1985 (See Section 5.1).
3.0 Summar of 0 eratin Events 3.1 Unit
Unit 1 continued full power operation throughout the period between January 7 and January 24, 1985; but, due to the gradual depletion of the fuel, the output decreased.
On January 24, 1985, Unit 1 scrammed from 82 percent power on a gen-erator load reject caused by a
generator neutral phase overvoltage signal.
The problem was traced to icing in the auxiliary transformer (T-11) isophase duct bus and a loose connection on the resistor bank connected to the neutral bus.
The unit returned to operation on January 26.
The coastdown will continue until the start of the first refueling outage, scheduled for February 9,
198.2 Unit 2 On January 7,
1985, the main turbine tripped twice on high vibration during the turbine startup.
After removal of a balance shot at the main turbine 5/6 bearing the turbine was returned to service.
On January 8,
1985, the main turbine tripped due to "A" moisture sep-arator drain tank high level caused by the feedback arm of the Emerg-ency Pump Valve not being in place.
The position feedback arm was adjusted properly.
The turbine was reset and synchronized to the grid.
On January 12, 1985, the HPCI system was declared inoperable when a
sheared stem was discovered on the turbine stop valve The valve was repaired and HPCI returned to service.
After delays in power ascension due to main turbine vibrations, Unit 2 reached 100% power on January 13, 1985.
On January 19, 1985 the reactor scrammed from 100% power due to main turbine high vibration when testing No.
1 control valve.
On January 20, the reactor was critical and the generator synchronized.
(See Detail 7.0)
At 5:54 a.m.
on January 29, 1985 the reactor scrammed during ST27.2 Generator Load Reject Test and entered Operational Condition
on January 30, 1985.
(See Detail 6. 1).
The unit reached criticality January 31, 1985.
The 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> warr'antly run commenced at 8:30 p.m.
February 4,
and was scheduled to be completed on February 9,
1985.
4.0 Licensee Re orts 4.1 In Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the accur-acy of description of the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
Unit
~84-048-00, Containment Purge Valves Damaged during Drywell Nitrogen Inerting
"*84-049-00, Missed Sampling Prior to Purge/High Oxygen Concentration
Unit 2 None
- Previously discussed in Inspection Report 50-387/84-38; 50-388/84-47
- "Further discussed in Detail 4.2 4.2 Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 4. 1), the inspector verified the reporting requirements of
CFR 50.73 and Technical Specifications had been met, that appropriate corrective action had been taken, that the event was reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits.
4.2. 1 LER 84-049 Hi h Containment Ox en Concentration and Missed Sam lin Prior to Pur e
This LER describes an event which occurred on December 14, 1984, when it was determined that suppression chamber oxy-gen concentration exceeded the Technical Specification limit of four percent, and on the subsequent suppression chamber purge, the required sampling and analysis was not performed prior to the purge.
Technical Specification 3. 11.2. 1 and Table 4. 11.2. 1.2-1 require that a sample be taken of the containment prior to purging.
Additionally, Administrative Directive AD-gA-309, step 6.3.6 requires sampling prior to purging'he Unit
suppression chamber was purged without a sample being drawn prior to the purge due to an oversight by the responsible Plant Control Operator (PCO)
and Unit Supervisor.
The licensee's corrective action included counseling of the responsible operators, and discussion of the event at the Shift Supervisors Meeting and Supervisor of Operations Meeting.
Chemistry analysis for suppression pool samples collected immediately after the purge were less than detec-table, and the purge was vented through the filtered Stand-by Gas Treatment System, which is continuously monitored.
At 3:00 a.m.
on December 14, 1984, control room operators
'oted that the oxygen concentration in the suppression chamber was 4.5%
as indicated by the
'B'ydrogen/oxygen analyzer.
The reading is taken once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> although Technical Specifications require only a
weekly reading.
The appropriate action statement, LCO 3.6.6.4, was entere Further licensee review of the previous days log for trend-ing information found that it also had recorded an oxygen concentration of 4.5%.
The licensee correctly revised the LCO entry date based on the December
readings.
Sup-pression chamber oxygen concentration was reduced below 4%
at 9:36 a.m.
on December 14.
The time limit of the LCO action statement was not exceeded.
The log reading on December
was not noted as exceeding the Technical Specification by the operator performing the surveillance, the shift supervisor or the STA who reviewed the completed surveillance.
These readings were the init-ial set recorded after the swap from the
"A" analyzer on December 12.
The previous days reading on the "A" analyzer for the suppression chamber was 3.0%.
The
"B" analyzer had been placed in service on December
following repairs and the "A" was taken out of service for routine calibration.
During the calibration, Instrumenta-tion and Controls Technicians noted that significant ad-justments had to be made to the
"A" analyzer.
Due to the adjustments the licensee concluded that the analyzer had probably been standardized on the wrong scale.
Review of the standardization procedure revealed that it did not in-clude a
step to select the proper scale while standard-izing.
The procedure has been revised to include the pro-per step.
The licensee has experienced continual difficulties with the hydrogen/oxygen analyzers as evidenced by numerous LER's and SOOR's.
They have proved to unreliable and have consistently proven to provide erroneous readings.
Due to the proven unreliability of the analyzers and the repeated SOOR's, further management attention appears war-ranted to provide accurate reliable indication to ensure containment oxygen concentration is maintained below four percent.
The licensee has performed an Engineering Evalua-tion as part of the corrective action to a previous LER, but no additional corrective action has been implemented.
This item remains unresolved and will be reviewed in a sub-sequent inspection.
(387/85-01-02)
4.3 Review of Periodic and S ecial Re orts Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector.
The reports were reviewed to deter-mine that the report included the required information; that test
results and/or supporting information were consi stent with design predictions and performance specifications; that planned corrective action was adequate for resolution of identified problems, and whether any information in the report should be classified as an ab-normal occurrence.
The following periodic and special reports were reviewed:
Monthly Operating Reports December 1984 Special Report RCIC Injections (Unit 2) dated January 4,
1985 The above reports were found acceptable.
5.0 Monthl Surveillance and Maintenance Observation 5. 1 Surveillance Activities The inspector observed the performance of surveillance tests to de-termine that:
the surveillance test procedure conformed to technical specification requirements; administrative approvals and tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance pro-cedure; 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 included:
S0-150-002, Quarterly RCIC Pump Flow Verification, performed on January 7,
1985 S0-159-010, Suppression Chamber Average Water Temperature Verif-ication, performed on January 7,
1985 S0-252-002,
Day HPCI Flow Verification, performed on January 7,
1985 S0-184-004, Monthly MSIV Leakage Control System Blower and Heat-er Operability Test, performed on January 9,
1985 S0-024-013, Offsite Power Source and Onsite Class 1E Operability Test (A EDG), performed on January 14, 1985
I
SM-113-008, Six Month Inspection and Weight of Halon Cylinders and Flow Verification, performed on January 23, 1985.
No unacceptable conditions were noted.
5.2 Maintenance Activities Between January 8 and January 29, 1985, the licensee performed the
month maintenance inspections and other associated maintenance on all four diesel generators, one at a time.
The 18 month maintenance con-sisted of the following: hot web checks, inspection of lower engine internals, checks of main and rod bearing clearances, inspection of main and auxiliary drives, checks of the fuel injector nozzles for pressure and spray pattern, visual inspection via borescope of upper engine internals, valve timing and tappet clearances, and preventive maintenance on auxiliary systems.
Other maintenance included circuit breaker inspections and cleaning, inspection and or replacement of pneumatic protection and internal system components, and tie-in of the new air dryers to the diesel air system.
The inspector observed portions of the maintenance on all diesels, reviewed work packages, and discussed the work with affected individ-uals.
No significant problems were encountered during the mainten-ance and the inspector observed no unacceptable conditions.
The inspector also reviewed control room logs, the diesel generator start log and results of surveillance S0-024-013, Offsite Power Source and Onsite Class 1E Operability Test, to verify that the licensee was meeting the requirements for verifying operability of the onsite sources and the remaining diesel operability of the off-site sources and the remaining diesel generators (D/G) when one D/G is out. of service.
During operability testing of the diesels between January 8 and 28, the licensee encountered the following problems:
The 'C'/G exceeded the
second start time on January 8.
The 'B'/G tripped on high connecting rod temperature several times over this period.
On January 25, three diesel generators were out of -service due to cold weather related problems.
The 'O'/G tripped twice on reverse power during post-mainten-ance testing on January 29.
The inspector discussed the above D/G failures with licensee person-nel.
The majority of these trips are non-valid because they involved misoperation of components which are bypassed in the emergency mode.
There have been several recurring problems which are discussed below:
4I l
A
Slow Start Times:
There have been a
number of occurrences of D/Gs exceeding the
second start time or tripping on overvol-tage due to a
slow start.
These problems have been traced to sluggish operation of the pneumatic fuel control trip valve (USCV-9) which is bypassed by two solenoid operated fuel control trip valves in the emergency mode.
Disassembly of the USCV-9 valves has shown evidence of corrosion apparently caused by moisture in the control air lines.
The licensee has now re-placed the USCV-9 valves on all four D/Gs and is installing air dryers in the diesel air system of all D/Gs to eliminate mois-ture problems.
A number of trips on D/G overvoltage are due to the slow starting.
This occurs because the overvoltage relay is frequency sensitive causing the relay pickup voltage to vary with frequency, i.e.
the lower the frequency, the lower the pickup voltage.
The voltage regulator is not speed or frequency dependent and if the D/G starts slowly the voltage regulator can increase voltage above the overvoltage relay pickup point caus-ing an overvoltage trip.
The licensee intends to replace with one which is not frequency sensitive.
High Connecting Rod Temperature Trips:
There have been several D/G trips on spurious actuation of the high connecting rod temp-erature mechanism.
This detector is located on each of the con-necting rods and consists of two spring loaded fuse rods sealed by a eutectic alloy material.
In a high temperature condition, the eutectic alloy melts, the fuse rods extend and on the next rotation of the connecting rod, the fuse rods strike a
small vent valve attached to the lower engine casing causing it to open and depressurize the pneumatic protection air header.
The eutectic alloys have never melted indicating that actual high temperature conditions have not existed.
(Maintenance personnel believe the cause of the trips appear to be oil splash from the connecting rod against the vent valve causing it to open).
Lowering the oil level in the crank case slightly has corrected the problem, although the vent valve, No.
5 cylinder on the
'8'/G, has misoperated on several occasions.
A Work Authorization has been written to replace this vent valve.
Reverse Power Trips:
On several occasions, D/Gs have tripped on reverse power shortly after loading the D/G on a bus.
The cause is generally inadequate response of the governor as the operator tries to pick up load during a surveillance test.
The inade-quate governor response appears to be due to cold governor con-trol oil.
This oil is cooled by Emergency Service Water (ESW)
which during cold days has been less than
degrees F.
The licensee has initiated a
modification to change the cooling water to the governor oil cooler from ESW to jacket water which is normally maintained between 120 130 degrees F.
At present, the licensee has not evaluated or implemented any interim cor-rective measures to prevent or minimize governor control prob-lems, until implementation of the modificatio During log reviews, the inspector determined that a Significant Oper-ating Occurrence Report (SOOR)
was not prepared following a trip on the 'C'/G due to overexcitation caused by operator error on January
nor was a
SOOR prepared to document trips of the 'B'/G on January
due to high connecting rod temperature.
In accordance with Technical Specification 4.8. 1. 1.3, all D/G failures, valid or non-valid, are required to be reported to the NRC within
days.
The SOOR is the internal reporting mechanism for determining report-ing of incidents to the NRC.
In response to the inspector's con-cerns, the licensee prepared SOORs on the above D/G failures and in-dicated that Operations Instruction OI-24-002, Diesel Generator Start Log, would be revised to emphasize reporting requirements for all D/G trips.
OI-24-002 will be reviewed when revised.
(387/85-01-03)
At the exit meeting on February 20, the inspector expressed concern with the relatively large number of D/G failures even though nearly all fai lures are due to misoperation of components which are not re=
quired in the emergency mode.
The inspector stated that additional management attention to the causes, corrective actions, and internal reporting of non-valid D/G trips may be warranted.
6.0 Startu Test Pro ram Unit 2 The inspector witnessed portions of selected tests to verify that:
Procedures with appropriate revision were available and used; Test changes were identified and implemented without changing the basic objectives of the test, in accordance with station procedures and Technical Specifications; Prerequisites were completed and verified; Initial conditions were met; Special test equipment required by the procedures was utilized and calibrated; Test was performed in accordance with the procedure; Results were satisfactory and met the acceptance criteria; Test exceptions or deviations were identified, documented and reviewe ST 27.2 Hi h Power Generator Load Rejection On January 29, the inspector witnessed Startup Test ST 27.2, Revision 4,
High Power Generator Load Rejection.
The purpose of the test is to demonstrate the response of the reactor and its control systems to the protective trips of the main turbine and generator.
The test was begun by opening the generator output breakers which is sensed as a
load reject and causes an automatic turbine trip.
Turbine bypass valves are required to open within 0. 1 seconds of initial turbine control valve movements.
A reactor scram and two recirculation pump trips occur on the turbine control valve fast closure.
No operator action that would prevent a
main steam isolation valve closure is permitted during the first three minutes.
Recovery is performed in accordance with the reactor scram and turbine trip procedures.
Following the trip, two safety relief valves opened to mitigate the reactor pressure increase, which peaked at 1077 psig.
Reactor vessel level oscillated between plus
and plus 39 inches and quickly stab-ilized at the normal level of 35 inches.
No major problems were en-countered during 'the performance of the test.
During the test re-sults analysis, the licensee determined that both recirculation pumps exceeded the flow coastdown time constant of 4.5 seconds.
The flow coastdown time is a level 1 test acceptance criteria and the licensee prepared Test Exception Report (TER) No.
187.
The resolution to this TER is that the licensee is unable to take credit for the end of cycle recirculation pump trip (EOC-RPT)
in Minimum Critical Power Ratio (MCPR) calculations.
This requires the licensee to set the MCPR limit at a value greater than or equal to the EOC-RPT Inoperable curve in Technical Specification 3.2.3.
This limit has been changed in the process computer.
All other acceptance criteria were met.
During the post trip review of the scram, the licensee determined that four control rods, i.e.
26-43, 10-23, 42-35 and 26-19, were slower than the remainder of the rods in reaching the notch 45 posi-tion.
The inspector reviewed the control rod data.
The slowest of the four reached notch 45 in 0.419 seconds, which is still less than the Technical Specification average limit of 0.43 seconds.
The aver-age of all rod speeds to notch
on the scram was 0.26 seconds'ecause of previous problems with scram pilot solenoid valves (SPSV)
(Ref:
Inspection Report 50-387/84-35, 50-388/84-44),
the licensee replaced the SPSVs on these hydraulic control units and intends to perform further testing on the removed SPSVs.
Scram testing of these four rods following the SPSV replacement indicated that the rods moved at a rate closer to the average of the rest of the rods.
This was the last major startup test.
The Unit 2 drywell and sup-pression chamber were inerted for the first time and the reactor re-turned to criticality on January 31.
Following low power HPCI test-ing, reactor power was increased in preparation for the full power warranty ru.0 Unit 2 Reactor Scram on Januar
At 11:54 a.m.,
on January 19, 1985, the Unit 2 reactor scrammed from full power due to main turbine high vibration while testing the turbine control valves.
The high vibration caused a turbine trip which caused a reactor scram when the turbine control valves fast closed.
The recirculation pumps tripped on the end-of-cycle recirculation pump trip and three safety relief valve's (SRV) lifted to mitigate the pressure increase.
Plant data showed that No.
1 turbine bearing increased in vibration from about 2 mils to 10 mils in a period of 18 seconds from the initiation of No.
1 control valve closure.
No specific cause of the high vibration has been found.
Instrument and controls personnel checked the trip setpoints of the vibra-tion monitor with no problems found.
A comparison of previous turbine vibration data during coastdown following a trip did not reveal any prob-lems.
On January 20, Unit 2 was restarted and made critical at 10 '5 a.m.
The unit was synchronized with the grid at 9:36 p.m.
and additional control valve testing was conducted at less than 24 percent power such that a tur-bine trip would not cause a reactor scram.
No problems were noted.
Tur-bine vibration data was monitored closely during power escalation.
Addi-tional control valve testing was successfully conducted at 78 percent.
Licensee is continuing to evaluate turbine data to determine if additional balance shots are needed.
The inspector reviewed plant operator logs, the sequence of events print-out, safety parameter display system data, and GETARs traces of the scram.
The licensee had noted that the 'C'RV lifted at 1071 psig,
pounds below its setpoint of 1086 psig.
The pressure switch was found low and recalibrated prior to startup.
The inspector noted that GETARs and SPDS data indicated that the 'E'RV lifted at 1071 psig but closed two seconds later at a
pressure of 1076 psig.
The 'B'nd 'C'RYs also lifted at 1071 but did not close until 12 seconds later when pressure reduced to 961 psig.
The inspector verified that the SPDS and GETARs data were obtained from the SRV acoustic monitor.
Computer data which indicated actuation of the pressure switch and tailpipe thermocouple data indicated that all three SRVs opened and shut simultaneously and were open for a duration of
seconds.
This data indicated that the acoustic monitor for the 'E'RV apparently.malfunctioned.
The inspector discussed this with licensee personnel and determined that the anomaly with the 'E'RV had been overlooked during the post trip re-view.
On January 24, the licensee performed SI-283.-326,
"18 Month Cali-bration of SRV Position Indication" for the 'E'RV acoustic monitor.
No problems were identified.
During the load reject test on Unit
on January 28, the 'E'RV lifted to mitigate the pressure increase, but the actuation was not seen by the acoustic monitor.
The licensee determined that the charging amplifier inside containment for the 'E'coustic mon-itor was faulty.
This amplifier was replaced prior to reactor startu 'll
8.0 Unit 1 Dr well Leaka e
Following reactor startup on January 26, the licensee began to experience increasing unidentified leakage in the Unit 1 drywell.
On January 31, unidentified drywell leakage reached 4.5 gpm (the Technical Specification limit is 5.0 gpm)
and drywell temperature approached the limit of 135 de-grees F.
Leakage and temperature remained at or near the limits until February 5 when unidentified leakage exceeded
gpm.
At about 5:00 a.m.
on February 5,
the licensee isolated the RCIC and Reactor Mater Cleanup (RWCU)
systems and electrically backseated six valves inside containment in an effort to reduce the leakage.
Following this action, unidentified leakage dropped to about 0.5 gpm, indicating that one or more of these valves were leaking.
The licensee later determined that leakage from the RCIC inboard steam isolation valve was the primary contributor to the dry-well leakage.
On January
and 31, the inspector reviewed licensee's drywell unidenti-fied leakage calculations and independently performed the calculation to verify that licensee's calculations are conservative.
The drywell uniden-tified leakage calculation is performed every four hours by determining the level changes in the drywell floor drain sumps.
The inspector also reviewed results of the monthly logic functional and 18 month channel cal-ibration surveillances.
The inspector also verified that the level re-corders ( LR16102 A and B)
used to perform the leakage calculation were calibrated.
With respect to the electrical backseating of the six valves inside con-tainment, the inspector discussed concerns about the backseating process with licensee maintenance personnel.
The valves were backseated by oper-ating the local contactors at the motor control center (MCC) which by-passed the motor torque and limit switches and over load contacts.
The licensee monitored the valve motor current on all three phases of the mo-tor leads using amprobes and operated the contactors until an increase was seen on the ammeters.
The containment isolation valves that were back-seated were declared inoperable and another operable valve in the line was shut.
Prior to returning the valve to operable status, the valves were cycled.
The licensee plans to internally inspect two of the valves for indications of damage and to conduct additional testing and evaluations of the six valves involved.
The inspector had no other concerns.
9.0 Alle ation 85-22 The inspector received an anonymous letter dated January 30, 1985, dis-cussing concerns with promotion practices in the Electrical and Structural Construction Department.
Based on NRC Region
review, the concerns in the letter do not involve matters appropriate for NRC regulatory involve-ment.
These concerns involve matters which may be within the jurisdiction of the U.
S.
Department of Labo. 0 Exit Interview On February 20, 1985, the inspector discussed the findings of this inspec-tion with station management.
Based on NRC Region
review of this report and discussions held with licensee representatives on February 20, it was determined that this re-port does not contain information subject to
CFR 2.790 restriction $
h l'
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