IR 05000423/1987008
| ML20214U769 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 06/05/1987 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20214U753 | List: |
| References | |
| 50-423-87-08, 50-423-87-8, NUDOCS 8706110333 | |
| Download: ML20214U769 (14) | |
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U.S. NUCLEAR REGULATORY COMISSION REGION I ,
Report N /87-08 Docket N License N NPF-49 -
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Licensee: Northeast Nuclear Energy Company P.O. Box 270 Hartford, CT 06101-0270 Facility Name: Millstone Nuclear Power Station, Unit 3 s
Inspection At: Waterford, Connecticut Inspection Conducted: March 17 - May 11, 1987 Inspectors: J. T. Shediosky, Senior Resident Inspector ' C , Resident , Inspector Approved by: #$
E. C. McCabe, C y eactor Projects Section 3B Date Inspection Summary:
Areas Inspected: Routine on-site resident inspection (121 hours0.0014 days <br />0.0336 hours <br />2.000661e-4 weeks <br />4.60405e-5 months <br />) of shutdown plan-ning, plant operations, radiation protection, physical security, fire protection,
surveillance and maintenance.
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Results: This inspection identified acceptable performance in all areas. However, the three reactor trips on low steam generator level (Details 1, 2.d, 2.e, and 2.1)
represent ongoing unnecessary challenges to safety systems because of feedwater control problems. Also, a safety injection system actuation (Detail 2.a) occurred due to a faulty procedure change. Problems such as these a .dications of
- operational performance weaknesses.
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f-TABLE OF CONTENTS PAGE 1. Summary of Facility Activities.....................,....,,,,,,,,,,,,, 1 2. Review of Specific Activities........................................ 1 Safety Injection System Actuation............................... 2 Discrepancies in Engineered Safety Features Component Response Times........................................................... 2 l "C" Main Steam Isolation Valve Failed Partial Stroke Test....... 3 a Reactor Trip-April 12, 1987..................................... 4 Reactor Trip-April 12, 1987..................................... 4 Improper Intermediate Range Neutron Flux Trip Setpoint.......... 5 Missing Chloride Detector Channel Check Documentation. . . . . . . . . . .
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6 Local Leak Rate Tests........................................... 7 Discovery of an Additional Instrument Inaccuracy in Steam Generator Water Level Indication................................ 8 Calibration Error to the Overtemperature Differential Temperature Setpoint............................................ 9 Investigation Into "B" Emergency Diesel Generator Problems...... 9 c Reactor Trip-May 7, 1987........................................ 10 3. Licensee Event Reports..................................,,,,,,,,,,,,, 11 4. Management Meetings................... .............................. 12 l
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PETAILS Summary of Facility Activities The plant was shut down on March 14 for a planned mid-cycle maintenance outag Activities included Engineered Safety Features (ESF) actuation testing with integrated loss of off-site power testing, seismic snubber testing, battery and battery charger capacity tests, local leak rate testing, and carbon di-oxide fire suppression system testing in the station service (normal) switch-gear area. Significant maintenance included replacement of three (3) reactor
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coolant pump seals, rebuilding of the pressurizer Power Operated Relief Valves (PORVs), repair of containment isolation valve local leak rate test deficien-cies, modifications to the Main Steam Valve Building ventilation system, re-pair of service water supply piping associated with heat exchangers, and re-pair of the "D" Steam Generator secondary hand hole gasket surface A plant heatup was started on April 4 and the reactor was made critical on April 6. However, the reactor was shut down and a plant cooldown was begun because the "C" Main Steam Isolation Valve (MSIV) failed stroke testing at 7:54 p.m. , April 6. Repairs to two (2) of the eight (8) solenoid operated control valves were completed and the reactor was made critical at 6:20 p.m.,
April 1 Two (2) reactor trips occurred on April 12. The first, from 66% reactor power at 6:18 a.m. , due to low steam generator level, followed a speed control
. oscillation of the "A" turbine-driven feedwater pump. The reactor was made critical at 12:06 p.m. A second reactor trip on low steam generator level followed a feedwater isolation (FWI) at 6:08 p.m. The FWI occurred during a steam generator level oscillation at 15% power while starting the main tur-bine. The reactor was again made critical at 11:08 Another reactor trip occurred at 7:44 p.m., May 7, on low steam generator level due to level oscillations which followed a rapid power reduction made in response to an apparent failed feedwater pump bearing. The reactor was made critical at 10:49 p.m., May 8, and operated through the end of the report period at a reduced power (69%) because of a feedwater pump seal reliability concer . Review of Specific Activities The resident inspectors observed plant operations, maintenance, and surveil-lance during regular and backshift hours including inspections made on April 12 in response to a reactor trip. Control room instruments were observed for correlation between channels, proper functioning, and conformance with Tech-nical Specifications. Alarm conditions in effect and alarms received in the control room were reviewed and discussed with the operators. Operator aware-ness and response to these conditions were reviewed. Operators were found cognizant of board and plant conditions. Control room and shift manning were compared with Technical Specification requirements. Posting and control of radiation, contaminated, and high radiation areas were inspected. Use of and
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compliance with Radiation Work Permits and use of required personnel monitor-ing devices were checked. Plant housekeeping controls were observed including control of flammable and other hazardous materials. During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication of equipment status. These records included various operating logs, turnover sheets, safety tag and jumper logs, process computer printouts, and Plant Information Reports. The inspector observed selected actions concerning site security including personnel monitoring, access control, placement of physical barriers, and compensatory measures. No unacceptable conditions were iden-tifie Safety Injection System Actuation One train of the Emergency Safeguards Features (ESF) System actuated a Safety Injection (SI) at 10:55 p.m., March 25, while Instrument and Con-trol Department testing was in progress on the "A" Solid State Protection System (SSPS). An injection to the Reactor Coolant System (RCS) did occur through the high head safety injection path. The RCS was being refilled after being partially drained for Reactor Coolant Pump seal maintenance during a mid-cycle maintenance outag Because of the sys-tems' alignment, the only result of the SI was to increase charging pump flow to the RCS from 80 to 200 gpm for about one minute as valve 3 SIH*MV8801A opene The cause of this SI was a deficient surveillance procedure. The test procedure step which was to place the affected portion of the system in a test mode was inadvertently deleted during a procedure revision. This has since been correcte The inspector reviewed the performance of equipment associated with the SI. Additionally, the inspector reviewed the licensee compliance with procedures for establishing cold overpressure protection (COPPS). There were no unacceptable conditions identifie Discrepancies in Engineered Safety Features Component Response Times While performing an 18-month surveillance on Engineered Safety Features (ESF) valve response times, a technician found that the eight main steam line 3-inch air operated drain valves did not close in the 6.8 seconds allowed for main steam isolation (MSI) by Technical Specification 3.3.2, Table 3.3-5. They closed in from 7.5 to 9.6 seconds. This was reported to the NRC via the ENS system. These valves' stroke times had previously been measured and evaluated against the Containment Isolation Technical Specification 3.6.3 Table 3.6-2 criterion of less than 10 second The ESF response time surveillance procedure had been revised since it was initially performed to include the eight valves in questio Following an additional engineering review, the licensee concluded that these valves were not included in the safety basis for the MSI function. This has been documented in a Safety Analysis reviewed by the Plant Operations
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. 3 Review Committee (PORC) at a meeting which addressed the subject Instru-mentation and Control surveillance procedures. Based on this safety analysis, application of the 10 second containment isolation criterion is prope In a separate matter, the licensee also investigated the charging pump suction transfer from the volume contact tank (VCT) to the Demineralized Water Storage Tank (DWST) after finding that it could not be accomplished within the 12-second Technical Specification allowance for ESF 3afety Injection (SI) actuation without a Loss of Power (Specification 3.3.2, Table 3.3-5). A protective interlock for the charging pump suction shift from the VCT at 4% VCT level to the RWST prevented the VCT supply valves from closing before the RWST valves fully open. Although the SI signal goes to both valves to shift pump suction to the RWST, during surveil-lance testing the licensee discovered that the interlock was not bypassed as was previously thought. Each valve had a stroke time of 11.4 second Because of the interlock, total actuation time on receipt of an SI signal was 22.8 second This exceeded the 12 second valu A Technical Specification Amendment (No. 3) was issued on April 9, 1987 to change the required response time by 15 seconds to 27 seconds with off-site power and 37 seconds without off-site powe There were no unacceptable conditions identified by the inspector's re-view, c. "C" Main Steam Isolation Valve Failed Partial Stroke Test The Main Steam Isolation Valves (MSIVs) were stroke tested and opened following a reactor startup on April 6. This startup concluded the mid-cycle maintenance and surveillance outage. During the testing of the
"C" MSIV, it shut fully during partial stroke testing. The licensee considered the valve to be inoperable and followed the Technical Speci-fication action statement for Mode 2. The valve was maintained closed and the reactor was shut down and cooled down to allow work on the MSIV solenoid The licensee contacted the vendor and was informed that one or two of the eight solenoid-operated valves associated with the redundant control-1ers for the MSIV may have been sticking in the energized position. This would have caused the valve to fully shut during part stroke testin A change in the clearances of the solenoid was suspected to have occurred when the valve seat and disk were lapped to reduce leakage. The clear-ance between the operating rod magnetic slug and the stationary compon-ents of the solenoid magnetic circuit was thereby reduced. Residual magnetism from the direct current solenoid was identified as having the potential to cause the valve (s) to remain energize .
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. 4 Vendor representatives assisted the licensee in restoring the required clearance to the solenoid magnetic circuit. This was accomplished by machining the stationary magnetic slug to obtain the specified 0.5 mm clearanc The inspector observed portions of this work along with the associated successful valve testing. The maintenance procedures, automated work request and quality control documents were reviewed. There were no un-acceptable conditions identifie d. Reactor Trip-April 12, 1987 A reactor trip occurred at 6:18 a.m., April 12, from 66% power due to low level in the No. 4 Steam Generator. At the time, the operators were increasing power during the startup following a scheduled mid-cycle maintenance outag Approximately 15 minutes prior to the trip, the operators had increased re ctor power from 56% to 66% within a 16 minute interval to avoid an area of steam generator level instability. When at 66% power,'the speed of the "A" turbine-driven feedwater pump began to oscillate. The control room operator placed the speed controller in manual in an attempt to stabilize the pump speed. Nonetheless, the level of the No. 4 Steam Generator dropped to the Reactor Protection System (RPS) trip poin After the reactor trip, the licensee identified an air leak in the supply line to the "D" feedwater regulating valve (air is used to open the valve against spring pressure). It is believed that this leak was the primary cause of the reactor tri Contributing to the trip were the pump speed oscillation The leak was repaired and the pump controller was tested. A vendor tech-nical representative was present. No problems were.found. Additionally, the pump responded properly during the subsequent plant startu The resident inspectors examined the events associated with this reactor trip including the licensee's corrective action Safety-related equip-ment was found to have operated properly following the trip. There were no unacceptable conditions identifie e. Reactor Trip-April 12, 1987 Following the 6:18 a.m. , April 12, reactor trip and completion of cor-rective actions, the licensee made the reactor critical at 12:06 A second reactor trip occurred at 6:08 p.m. while at 15% power. The trip was due to low steam generator level in the No. 2 Steam Generato .-
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, 5 The cause of this event was operator error. Power was being increased from 15% during turbine warming. The turbine bypass steam dump valves and control rods were in manual. Steam Generator levels began to oscil-late. The control room operators attempted to stabilize level using manual control of the feedwater regulating bypass valves. Level in the No. 3 Steam Generator rose high enough to cause a Feedwater Isolatio Although the operators started the Auxiliary Feedwater (AFW) system in an effort to maintain level, they did not shut the turbine bypass steam dump valves. The steam generator inventory loss due to this steam demand was greater than that which could be supplied by the AFW syste The oscillation in level was caused by the high capacity motor-driven feedwater pump and difficulties in control of feedwater pressure. The operators attempted to dampen the oscillations by increasing power to a region of improved stability due to higher feedwater flow. During this time, they tried to regulate pressure and feedwater bypass valves in manual control. A Feedwater Isolation was received. The operator failed to recognize that the turbine bypass steam dump valves were in manual and dumping steam, and the result was the low steam generator level which caused the tri The licensee's corrective actions included a detailed discussion of the reactor trip with all licensed operators. Additional procedural guidance was provided to the operators on appropriate methods of maintaining steam generator level during plant startu The inspectors reviewed the events related to this reactor tri Safety-related equipment was found to have operated properl There were no unacceptable conditions identifie The reactor was again made critical on April 12 at 11:08 The plant reached full power at 1:00 a.m., April 1 f. Improper Intermediate Range Neutron Flux Trip Setpoint During the power ascension on April 11, the control room operators ob-served that the Intermediate Range neutron monitor IRM channels reached their high flux trip point at about 27%. This was logged and a trouble report was written. The plant was not in a Technical Specification Limiting Condition for Operation at the time because power level was above the P-10 low setpoint power range neutron flux interlock setpoint (Ref: Technical Specification Table 3.3-1.5). Since the as-found trip setpoint was greater than the Trip Setpoint of 25% but less than the Allowable Value of 30.9%, the action required by Specification 2.2. was to adjust the instrument setpoint to within the trip setpoint valu However, the associated trouble report was not pursued immediatel A reactor trip occurred at 6:18 a.m., April 12, and the reactor was subse-quently made critical at 12:06 p.m. without readjusting the IRM trip setpoin _
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Prior to this reactor startup, the Shift Supervisor consulted with the
- - on-shift reactor engineer, who believed that based on recent calibration data a readjustment of the intermediate range trip point was not require The reactor tripped again on April 12 at 6
- 08 p.m. During the post-trip
, review, the Unit 3 Reactor Engineer discovered that corrective action had not been taken on the setpoint problem. A recalibration was per-formed prior to the second reactor startup on April 12. The protective instrumentation performed properly during the startup and power ascensio Two problems became apparent during the inspector's review of this issu The first related to the Technical Specification requirements and the method of calibration. The intermediate range monitor system displays in units of detector amperage while the Technical Specification estab-p-
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lishes a Trip Setpoint relative to rated thermal power. The most reli-able method of calibration of the IRM high flux trip point involves a calorimetric performed at a reactor power near the required setpoint of 25% rated thermal power. At this power level, the IRM channels are sen-sitive to control rod bank position. Subsequent reactor startups at different control rod bank positions will affect the actual trip point relative to thermal power. In addition, periodic calibrations of the IRM high flux trip point are made at full power. Based on these, the IRM trip point is set at less than 25% of detector full power curren Recent inservice testing has confirmed detector non-linearity above 90%.
The licensee is re-evaluating engineering procedures to optimize per-formance of these trip sub-systems. No trip values outside the allowable range have been identifie The second problem relates to the administrative controls for post-trip review of recorded deficiencies. In this case, the inspector found that an incorrect decision was made by the Shift Supervisor and duty reactor engineer. This was due to improper interpretation of Action Statements for Specifications 2.2.1 Table Item 2.2-1.5 and 3.3.1 Table Item 3.3- and their relation to required actions for instrumentation with trip points less conservative than the stated Trip Setpoint but within the requirements of the Allowable Valu These items were still under licensee review at the conclusion of the inspection. It appears that there were two error The first was fail-ure to take prompt corrective action on re-calibration. The second was failure to track a plant condition which would cause entry into a Tech-nical Specification Action Statement in the event of a Mode Chang These matters are unresolved (50-423/87-08-01) pending completion of licensee and NRC review Missing Chloride Detector Channel Check Documentation On March 17, 1987, the licensee reported that chlorine detector channel checks were not conducted within the frequency specified in Technical Specification (TS) 4.32.7 The chlorine detectors actuate control building isolation to protect plant operators from an adverse external
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. 7 environmen TS 4.3.2.7f requires a channel check of the chlorine de-tectors every 12+/-3 hours and licensee surveillance procedure SP3670.2, TS Related Plant Equipment Operator (PE0) Rounds, implements this test by documenting verification of system operation on each shift. Shift Supervisor review of the SP3670.2 logs on March 17 revealed that the chlorine detector checks were not documented on the previous mid shift surveillance data sheets. Further review indicated that the test may not have been conducted for about 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. The licensee promptly veri-fied that the chlorine detectors were operating properly and initiated a plant information report (PIR87-62) to determine the appropriate cor-rective action Further licensee investigation fotnd that the mid-shift PE0 had done a channel check of the chlorine detectors and logged its completion on another log sheet. This was apparently a routine practice because cer-tain TS surveillances are most efficiently conducted during routine operator rounds, but the TS surveillance data sheets are not designed to accompany the rounds of any particular PE The operator subsequently forgot to fill in the surveillance check off sheet in procedure SP367 The licensee promulgated guidance requiring each shift supervisor to review the logs for his shift prior to turnover to assure that all re-quired actions are complete and documented during each shift. The in-spector discussed with the Operations Supervisor the practice of con-ducting surveillance activities separate from the approved implementing procedure Specifically, conducting a surveillance during operator rounds and later transposing documentation of these checks to a master document invites problems due to human error. The shift supervisor verification of TS surveillances provides more timely assurance of the completion of required tests. The licensee also indicated that operator rounds and surveillance documents were due for review and improvement and that consideration would be given minimizing the human factors con-cern. The inspector had no further questions on this ite h. Local Leak Rate Tests From March 16-20, 1986, the inspector reviewed local leak rate testing conducted in accordance with procedure SP36128.4. On March 17 the leak-age for residual heat removal isolation valve 3RHS-M0V8702A was found to exceed the capacity of the specified leak rate measuring device. The licensee subsequently measured the leak rate of this valve and others using a high volume test rig. The actual leak rate for 3RHS-M0V8702A was a small percentage of the overall allowable leak rate of 898,200 scc / min (0.6 La). Several penetration isolation valves tested during this period exceeded conservative administrative leak rate limits set by the licensee to assure the overall leakage is below the 10 CFR 50 Appendix J acceptance criteria for LLRTs. The licensee repaired several of the significant contributors to the leak rate, leaving the as-left leakage as 38.2% of 0.6 La. The inspector reviewed procedure SP36128 including the temporary change to incorporate the use of the high volume
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.s test rig on March 17, and the completed procedures for_ isolation valve 3RHS-MOV-8702 No discrepancies were identified. The inspector had no further' question Discovery of an Additional Instrument Inaccuracy in Steam Generator Water Level Indication Since_the beginning of power operations, Millstone Unit 3 has~ experienced steam generator level oscillation problems when operating between 50%
and_65% of rated thermal power. Investigation has led the licensee'to attribute the oscillations to the design of the level. sensing reference'
leg condensate pots and the associated fill and drain tubing connected between the pot and the steam generator shell. During a plant heatup-and startup conducted dur.ing the week of April 12, _ the_ licensee gathered
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temperature data from-the reference leg sub-system which confirmed engi-neering calculations. Those worst. case calculations indicate that, with the condensate pot tubing filled with water, an additional 13.1% error is introduced to the narrow range steam generator level instrument. This error _had not been included in the inaccuracies assumed for' steam genera .
tor level in the safety analysi The-root cause of the problem was. identified as relating to the size of'
the level instrumentation reference leg condensate pots and the' size and configuration of the associated piping between the' steam generators an those condensate pots. This problem is unique'to Millstone Unit 3, which
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the licensee has identified as the only United States reactor with con-densate pots designed to Instrument Society of America standards. iThe
~ Millstone 3 pots.have a significantly larger heat transfer area'(about 20 times) than the standard condensate pot installed with Westinghouse Model F steam generator The licensee plans modifications, during the 1987 refueling outage, to replace the existing condenser _ pots wit smaller one .The NSSS vendor, Westinghouse, has provided a safety analysis which forms
'the basis for a justification for continued operation. That analysis concluded that this newly identified error and the potential for less steam generator secondary mass volume did not affect power operation-below 70%. For power levels greater than 70%, the low level trip set-point must be. raised to accommodate the increased error. The Feedwater System pipe break.is the limiting transient at these higher power level To comply with this analysis, reactor power was reduced from full power to 70% at 0928, April 15. The low steam generator level reactor trip setpoints were raised an additional 13.1% to compensate-for the maximum possible calculated error. The Technical Specification Trip Setpoint is 23.5% (or greater). To allow operation above 70%, the setpoints were reset to 36.6%. When reducing power below 70%, the licensee plans to reset the setpoints to 23.5%.
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L,: 9 In an attempt to avoid reactor trips caused by steam generator level, the. operating (programmed) level was raised from 50% to 58%. This ap-
. pears to be at least partially effective as the control room operators were able to prevent a-reactor trip due to a. steam. generator level transient caused by the trip of all the fourth point heater drain pumps at 10:15 a.m.', April 2 The inspectors reviewed the licensee's safety. analysis, which. include a Westinghouse safety evaluation. These documents were accepted by the Plant Operations Review Committee which concluded its review on May Because this event identified an error in-the accuracy of values assumed by the Final Safety Analysis Transient Analysis, the licensee was asked to send a copy of their'. analysis.to the NRC Office of Nuclear Reactor Regulation. The: inspector had no further questions at this tim Calibration Error to the Overtemperature Differential Temperature Setpoint On~ April 16, the licensee' verified that'the non-conservative flux penalty calculation in the Reactor Protective System overtemperature differential temperature (OTdT) network, first discovered at Shearon Harris on April 15, also existed at Millstone The problem was found to be the use of an ungrounded negative test signal lead when. calibrating the process rack for adjustment of the lower flux' potentiometer, ultimately resulting in the negative flux penalty beginning at -34% instead of the -30% design-value. [The negative field lead coming from'the Nuclear Instrumentation System (NIS) is grounded at the NIS cabinet].
Calibration procedures were revised at Millstone to use a grounded nega-tive test lead to duplicate the grounded field lead. .Recalibration of all 4 OTdT channels commenced at about 1500, April 16 and were' completed at 4:07 p.m. that da The: inspectors reviewed the licensee actions; there were no unacceptable conditions identifie Investigation Into "B" Emergency Diesel Generator Problems The "B" Emergency Diesel Generator (EDG) was tested on May 6 following-routine preventive maintenance. The acceptance test start was made at 2:41 p.m. in 10.-06 seconds. This exceeded the Technical Specificatio maximum of 10 second Although one hot start made at 4:20 p.m. resulted in an acceptable time (9.83 seconds), subsequent starts took 10.57 and 10.75 seconds. After the first of these two starts was made at 10:05 p.m., the' engine tripped (at 10:17 p.m.). No flags or annunciators accompanied the engine shutdow Licensee investigation found that the air start solenoid pilot valves needed to be rebuilt and have their pickup voltage adjusted. The licen-see contacted the vendor, who recommended a valve pick-up voltage of 85
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were.not found-to be contaminated by foreign material. - Starting per :
formance improved following maintenance. In a test conducted at 9:45-p.m., May 7, the' engine started'in 8.85 second The-starting' times of each emergency diesel _.are included in the licen-
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see's trending program. ~As a result of the findings on the "B" EDG and of this trending program, similar preventive maintenance was performed on the "A" EDG. Its starting times, which were within limits, were also reduce Concerning the engine trip, it was found that, with the crankcase' vacuum near the set point of the low vacuum (high pressure) switch, engine vibration caused the switch to momentarily pick up and operate the engine shutdown relay. The momentary closure of the contacts was not of suffi-cient duration to pick up the annunciator circuit for:this shutdown feature. However, these events were recorded on high speed test equip-
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The licensee determined that a procedure change was require'd to define
'the method of adjusting crankcase vacuum during normal engine operation.'
The inspector monitored the licensee's testing and evaluation program and concluded that improvements have been made in emergency diesel engine reliabilit Concerning.the low vacuum engine shutdown, that function-is removed during a run initiated by the engine sequencer (emergency operation). The inspector found that-the licensee confirmed circuit independence of the auxiliary trip features for emergency operation dur-ing their investigation. There were no unacceptable conditions identi-fie . Reactor Trip-May 7 A Reactor Trip occurred due to ' low steam generator level at 7:44 p.m. ,
May 9 following a rapid power reduction made in response to an apparent failed feed pump bearing. The power reduction resulted in feed system instabilities, trip of the heater drain pumps, and eventual-. low steam generator leve All systems-performed correctly following the tri The circumstances concerning this power reduction _were unusual in that the plant operators attempted to rapidly remove a_ feed water pump from service due to-a significant bearing oil leak and high bearing _ tempera-tures. There was no damage caused by the oil spray, which extended 15 to 20 feet from the pump. However, the power reduction from near full power to 60% power in nine minutes resulted in feed system instabilitie Investigation found that the bearing was not damaged but that-the oil spray resulted from leakage due to high oil temperatures. The oil cooler is adjusted manually.and apparently was not providing sufficient coolin _ _ _ _ - _ _ _ _ _ _ _ _ _ _
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. 11 The reactor remained shutdown until the problems with the "B" Emergency Diesel Generator were resolved. The reactor was then made critical at 10:49 p.m., May 8, and reached full power at 3:18 a.m., May 1 The inspector.followed the licensee's post-trip revie There were no I unacceptable conditions identifie . Licensee Event Reports-LERs submitted during this report period were reviewed. The inspector assessed LER accuracy, whether further information was required, if there were generic j implications, adequacy of corrective actions, and compliance with the report- l ing requirements of 10 CFR 50.73 and Administrative Control Procedure ACP-QA-10.09. Selected corrective actions were checked for thoroughness and imple-mentation as documented elsewhere in this report. The LERs reviewed were:
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87-008-00 Reactor Trip due to Low Steam Generator Level caused b failed solenoid valve, March Setpoint drift Pressurizer Safety Valve Inoperable channel of RCS loose parts detection syste .16K Emergency safeguards bus undervoltage trip setpoint drif Failure to include five seismic snubbers in visual sur-veillance progra Failure to provide three electrical circuits with second-ary overcurrent protection for containment penetrations.
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87-014-00 Failure of "B" Emergency Diesel Generator to start in less than 10 seconds.
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87-015-00 Inability of MSIVs to close within the required time.
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87-016-00 Partial Safety Injection actuation caused by a defective procedur Failure to adequately determine and measure response time Control Building ventilation radiation monitor inoperable due to personnel erro Special report concerning elevated temperatures in an area with environmentally qualified electrical equipmen Reactor Trip due to low steam generator level, April 1 .. .
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87-021-00 Feedwater Isolation and Reactor Trip due to steam genera-tor water level transient, April 1 Discovery of an inaccuracy in steam generator water level indicatio Special report concerning elevated temperatures in an area with environmentally qualified electrical equipmen No unacceptable conditions were identified. When additional follow-up was .j considered appropriate, such follow-up was accomplished as documented in the 1 preceding sections of this report.
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4. Management Meetings )i i During this inspection, periodic meetings were held with senior plant manage-l ment to discuss the inspection scope and findings. No proprietary information ( was identified as being in the inspection coverage. No written material re-lating to inspection findings was provided to the licensee by the inspector.