IR 05000289/1988018
| ML20207M274 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 10/12/1988 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20207M246 | List: |
| References | |
| 50-289-88-18, NUDOCS 8810180212 | |
| Download: ML20207M274 (32) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Decket/ Report No. 50-289/83-18 License: OPR-50 Licensee: GPU Nuclear Corporation P. O. Box 480 Middletown, Pennsylvania 17057
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Facility: Three Mile Island Nuclear Station, Unit 1 Location: Middletown, Pennsylvania Dates: July 16 - August 27, 1988 and September 1, 1988 Inspectors: R. Conte, Senior Resident Inspector D. Johnson, Resident Inspector T. Moslat, Resident Inspector A. Sid; ara, Resident Inspector (Reporting Inspector)
Approved by: @ 6--- 4 N gYll, Chief, Keactor Projects Section'1A g // M Date Jns I ection Sumary: The resident inspectors conducted routine safety inspections of plant outage activities, plant startup evolutions, and power operations. The inspectors reviewed the following functional areas: plant operations, equipment operability (maintenance and surveillance), engineering support, and radiological controls. See Table of Contents for more detail Insgection Results: Plant operations were generally conducted in a safe manner, iiie fuil shuf flEplant heatup, as well ts power ascension, proceeded without any significant problems. The various startup-related tests anti surveillances were acceeplished in accordance with the established procedures. Some deficiencies were noted in the area of svitching and tagging of valves, such 45 the current status of the switching and tagging log did not reflect disposition of removed blue and red tags. The physical position of all the valves observed, however, was found to be in accordcnce with the valve line-up procedure Additional emphasis needs to be placed on identification of low threshold events so that appropriate reviews can be mad The overall niaintenan:9 and surveillance activitie;, were conducted quite wel The inspectors, however, acted some weakness in the areas of implementation of maintenance procedures and adequacy of documentation. A violation on failure to properly change maintenance instructions was identified (paragraph 3.7).
The licensee response in addressing the unresolved items identified during previous inspections was timely and the quality of .esponse was adequate. A violation of Technical Specific 6tions was identifieo in a licensee event report during this re-view (paragraph 3.6).
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The overall quality of housekeeping and radiological controls throughout the plan * ;
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remained of high qidality. The management involvement in reducing radiation expo- .
ture, as well as skin contamination, was eviden t 4 -
The planning, management, and control of the 7R refueling outage activities were i
] quite effectiv The outage was completed ahetd of schedule with increased scope '
j of work without any significant industrial or radiological safety incidents.
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, 3, TABLE OF CONTENTS
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PAGE 1.0 Introduction and 0verview............................................ 1
~ Licensee Activities.............................................
1.2 NRC Activities.................................................. .
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1.3 Persons Contacted............................................... 1 2.0 Plant Operations (NIP 71707)......................................... 2
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2.1 Criteria / Scope of Review........................................ 2 2.2 Plant Startup Activities........................................ 2 2.3 Event Review and Evaluation..................................... 3 2.4 Valve Line-Up Review /Startup Procedure Review................... 6 2.5 Reactor Coolant Pump Trip, Reactor Protection System / Heat Sink Protection System Actuation................................... 8 2.6 (Closed) Unresolved Item (289/88-13-06): Pressurizer Cooldown Event (NIP 92700)............................................. 11 l 2 . 7 O p e r a t i o n s S u mm a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 3.0 Equipment Operability Review - Maintenance / Surveillance (NIP l 61726/62703)............ .......................................... 13 i
3.1 C ri te ri a/ Scope o f Revi ew. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 3.2 Letdown Sample Valve Operability................................ 13 3.3 Condensate Pump Discharge Piping Support........................ 13 3.4 Safety-Rel ated CheckcValve Inservice Testing. . . . . . . . . . . . . . . . . . . . 14 l 3.5 Two-Hour Back-Up Instrument Air Compressor Surve111ances........ 14 :
3.6 Reactor Bui ldi ng In spection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 3.7 (Closed) Unresolved Item (289/88-13-03): Pressurizer Relief Valve Ta11 pipe Support Loose Bo1ts............................ 15 3.8 Eq ui pmen t Op e rabi l i ty Sunna ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 4.0 Engineering Support (NIP 37700)...................................... 16 4.1 Criteria / Scope of Review........................................ 16 i
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4.2 Diesel Cooling Water Temperature Instrumentation Modification... 16 4.3 Fuel Handling Bridge Modifications............ ................. 17 4.4 Cycle 7 Fuel Load and Physics Testing........................... 18 4.5 (Closed) Unresolved Item 289/88-08-01): RC-V-28 Environmental ,.
Qualification.................................................. 21 4.6 (Closed) Unresolved Item (289/88-13-05): Borated Water Storage Tank Vortexing................................................ 21 4.7 (Closed) Unresolved Item (289/88-13-07): Control Building Ventilation System Booster Fans Modification.................. 22 4.8 En g i n e e ri n g S u p po r t S umma ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
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" 5.0 Radiological Controls............................ ................... 23 S.1 Radiation Surveys............................................... 23 5.2 Decontamination of Transfer Cana1............................... 23 5.3 (Closed) Unresolved (289/87-09-02): RM-A-E/15 Process Radiation Monitor....................................................... 24 5.4 Ra d i ol og i c al Co n t rol s S uma ry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 6.0 Exit Meeting......................................................... 24~ m :-
ATTACHMENT ;
Attachment 1 - Activities Reviewed 1
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OETAILS 1.0 , Introduction and Overview 1.1 Licensee Activities During this inspection period, following the fuel shuffle, the licensee accomplished soveral major activities, such as: on August 7, 1988, the Reactor Coolant System (RCS) was pressurized by drawing a pressurizer stese bubble and, on August 12, 1988, decay heat removal (DHR) operations siere secured, plant heatup commenced, and plant hot shutdown condition achieved at 5:26 p.m. The reactor was critical on August 14, 1988, at 2:15 p.m. The main turoine was synchronized to the regional electrical grid on August 16, 1988, at 6:24 p.m. As of August 27, 1988, the plant was operating at 100 percent power level without any major components out of service. The 7R refueling outage was completed four days ahead of schedul .2 NRC Staff Activities The purpose of this inspection was to assess licensee activities during the plant shutdown, heatup, and power operations modes as they related to reactor safety, safeguards, and rad',ation protection. Within each area, the inspectors documented the specific purpose of the area under review, acceptance criteria and scope of inspection, along with appro-priate findings / conclusions. The inspectors made tnis assessment by reviewing informatior, on a sampling basis through actual observation of licensee activities, interviews with licensee personnel, measurement of radiation levels, or independent calculation and selective review of listed applicable document NRC staff inspections are gener .'y conducted in accordance with NRC In-spection Procedures (NIP's). These NIP's ar., noted under the appropriate section in the Table of Contents to this repor .3 Persons Contacted During this inspection, the following key licensee personnel provided substantial information in the development of the in:pectors' finding *G. Broughton, Operations / Maintenance Director
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- J. Colitz, Manager, Plant Engineering
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- D. Ethridge, Radiological Engineering ;. Acting) Manager
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- H. Hukill, Vice President and Director, TMI-1 s
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C. Incorvati, Audit Manager
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- M. Nelson, Manager, Safety Review
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'S. Otto Licensing Engineer
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- H. Wilson, Supervisor, Preventive Maintenance
-- M. Ross, Plant Operations Director
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H. Shipman, Plant Operations Engineer
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D. Shovlin, Plant Materiel Director
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C. Shorts, Project Manager, Site Technical Functions '
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C. Smyth, Manager, Licensing 2.0 Plant Operations 2.1 Criteria / Scope of Review The resident inspectors periodically inspected the facility to determine the licensee's compliance with the general operating requirements of Section 6 of Technical Specifications (TS) in the following areas:
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revi3w of selected plant parameters for abnormal trends;
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plant status from a maintenance / modification viewpoint,-including plant housekeeping and fire protection measures; ,
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control of on going and special evolutions, including control room !
personnel awareness of these evolutions;
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control of documents, including logkeeping practices; c 4 --
implementation of radiological contro?s; and,
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implementation of the security plan, including access control,
- boundary integrity, an,d badging practice During the transition from cold shutdown to power operations, the resi-
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dent inspectors provided enhanced coverage during back shifts and that weekend. Detailed findings are addressed below (see also Attachment 1).
2.2 Plant Startup Activities The inspectors commenced extended observation of con!.rol room operations and act.tvities within the plant on August 12, 1988, and completed this -
- coverage on August 18, 1988. This coverage included review of startup l activities during back shift and weekend hours. The inspectors observed plant heatup testing activities while the plant was in hot shutdown, reactor startup activities, power ascension, and physics acceptance
- testing of core parameters. The following observations were me>.
l On August 13, 1988, at 10:00 a.m., the inspector noted that NI-22, the
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new post-accident full range nuclear instrument installed per Regulatory Guide (RG) 1.97, was reading approximately four decades higher than NI-11
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and was slowly drifting down scale. No explanation could be determined by plant maintenance or operations personnel. The problem with NI-12 was previously identified by the NRC startup team irspectors and is being tracked separately. The high up-scale reading was noted again approxi-
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mately eight hours later and again on August 14. NI-11/12 were both successfully calibrated at 100 percent power on August 22, 1988, but the l
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licensee is presently planning additional troubleshooting efforts to identify the cause of erratic readings on NI-12 at lower power level The inspectors will routinely follow licensee efforts to determine the cause of NI-12 erratic readings at low power (see also NRC Inspection Report No. 50-289/88-17).
During the heatup and startup, the downstream temperature for RC-RV-1A, one of two pressurizer code safety valves, increased above the normal differential temperature limit of 30 The differential temperature between the tailpipe and containment temperature is normally less than 30 F; but, apparently, due to a small amount of seat leakage, this tem-perature had increased to approximately 60 F. The licensee completed a change to the pressurizer operational procedure (Operations Procedure (0P) 1103-5) to allow the alarm setpoint to increase to 80 F. The new setpoint would give an alarm to alert operators of any change in leakage ;
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The inspector reviewed the safety evaluation completed for the change in the setpoin The licensee acknowledged that the valve was probably leaking slightly and that the leakage may increase. The temperature was being trended on the plant trend recorders in the control room. Addi-tionally, the RCS leak rate determination has not indicated any suostan-
- tial leakage from the RCS. If the leak does increase substantially, this leakage would be identified by an increase in the F.CS leak rate calcula-tio The ir.spectors concluded that appropriate licensee action was taken for this problem and the inspector will continue to routinely monitor this area for any change in the condition of RC-RV-1 .3 Event Review and Evaluation
l In response to the latest Systematic Assessment of Licensee Performance j (SALP), the licensee has initiated a change to their Administrative Pro-l cedure (AP) 1029, Revision 31, "Conduct of Operations," to provide a methodology for disposition of incidents or abnormal conditions that are identified during plant operations. The licensee classified these events in three categories: Level I, Level II, and Level II Level I events are minor in nature and are dispositioned by the shift supervisor but are not entered in shif t logs; Level II events are logged and, depending on the circumstances, may be resolved by shif t supervisors and/or may i receive additional multi-disciplinary review. Level III events are logged and reported / reviewed by other methods, such as the Plant Incident Report (PIR) system, post-trip reviews, radiological awareness reports,
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and quality assurance reports such as Quality Deficiency Reports (QDR's)
l and Material Non-Conformance Reports (MNCR's).
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The inspector focused on a review of several recent log entries during startup activities, which were resolved on shif However, it appeared that these events needed additional review and resolution using the Level II classification, which apparently was not invoke On August 6, 1988, at 10:48 a.m., the Shift Foreman Log noted that DH-P-1A was secured due to OH-V-1A stroking closed. This occurred when the Motor Control Center (MCC) breaker for DH-V-1 was closed and the auto close signal was not reset. No other information was provided. Further review revealed that re-energization of the power supply to DH-V-1A was in progress after cleaning of the associated switch gear. The operator failed to accomplish a step in the procedure to reset the auto close signal in the Engineered Safeguard Actuation System (ESAS) cabinet Licensee corrective action was to counsel the individual involved. This performance problem was not processed for independent review; and, therefore, the opportunity for operational enhancement was los Another problem identified on August 7, 1988, at 6:51 p.m. was the loss of approximately 3500 gallons of water from the "A" Once-Through Steam Generator (OTSG) through the main steam and emergency feedwater (EFW)
system vents to the intermediate butiding. This event was recorded in the shift foreman's (SF) log. The licensee had been recirculating the
"A" 0TSG using Operating Procedure (0P) 1106-16, Revision 39, dated July 11, 1988, "0TSG Secondary Fill, Orain and Layup." t.icensee personnel observed over several shifts that inventory was being slowly lost during recirculation, but it was not apparent where the loss was occurrin Subsequently, on August 7, 1988, the licensee discovered an EFW pump steam trap drain valve cracked open in the intermediate building. Ap-parently, the slow manner in which water inside the OTSG was flowing between the downcomer and tube region caused the operators problems in determining actual OTSG level. The leakage was not a significant problem, as the water was not contaminated and no equipment was damaged. The licensee evaluated the situation and determined that a revision to the operating procedure was not required. The event was communicated to operating personnel via shift briefing A third problem occurred when the "D" Reactor Protection System (RPS)
channel actuated a reactor trip on high reactor building (RB) pressure caused by the inadvertent opening of an instrument air valve (IA-V-245).
This was a log entry on August 4, 1988, at 4:03 p.m. The cause was later determined to be an auxiliary operator who checked a shut valve in the open direction. This was not normal procedure, but was evaluated as an isolated occurrence. The operator in question was counseled as correc-tive actio On August 1, 1988, an auxiliary operator attempted to line up the "A" decay heat loop to the "B" precoat filter for cleanup and purification of reactor vessel water. Flow could not be established because a flow path isolation valve was still shut. Apparently, the operator misread
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a valve number from the applicable procedure. Although initially con-fused, he found the mistake with the help of the shift supervisor, who happened to be in the area. Flow to the "B" precoat filter was then properly established. Operators made no log entry on this error. Al-though the "event" did not meet the "significance" criteria of AP 1012, it was a performance problem that might warrant further review now or in the future. However, without the event being recorded, the opportun-ity for operational enhancement was los Two other log entries that were classified as Level II did receive addi-tional revie One, or. July 29, 1988, during restorstion from preventive maintenance on the IS 480-volt a.c. switch geer, a phase to ground fault occurred on the "1B" battery charger breaker, which was being closed. The breaker did not trip, but the IB ES MCC feeder breaker on the IS 480-volt switchgear did trip. The "B" battery charger breaker is located on the
"1B" MC The licensee initiated a review of this event via the criteria of the guidance in AP 102 This was deemed to be an event or abnormal condi-tion which required additional multi-disciplinary review. A Plant Review Group (PRG) meeting (No. 83-53) on August 2, 1988, was held to discuss the event. Several recommendations were made. Maintenance was to review Preventive Maintenance Procedure (PMp) E-1 to determine if additional guidance was needed for Inserting units into the MCC and investigate whether solvent / water used in cleaning may have caused the fault. Engi-neering personnel were to investigate if ground fault protection was feasible. The result of the above evaluations was that it was not feas-ible to install ground fault protection. Although no positive long-term corrective action was required as a result of this event, plant engi-neering and maintenance personnel were able to review the circumstances l
and provide their input. Also, the event is now entered in a system that can be reviewed at a later dat The second event, the loss of all four RCP's is discussed in Section of this report.
! In some of the events noted above, procedure nonadherence is noted. This
- s a current open issue at TMI-1; and, accordingly, no enforcement action will be taken. The purpose of this review is to assess licensee review of such event The inspector questioned the licensee on the criteria that is to be used by shift supervision to make a decision as to which log entries for ab-normal conditions need further followup by use of Enclosure 4 to Ap 1029 and which entries need no further formal followup or recording in the logs. The licensee representatives responded that AP-1012, "Logkeeping,"
was to be revised to designate which type of low threshold events is to be logged and escalated for further review. At present, no specific
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criteria exists for generation of an Erclosure 4 form (Level II review).
This form allows plant management to re,tew the significance of low threshold event The inspector concluded that licensee effort to formulate a system to encourage multi-disciplinary review of plant events was still an evolving process. Sufficient guidance does not exist yet to ensure that low ,
threshold events receive the proper independent evaluation and revie The inspectors will continue to follow the resolution of this concern when changes to AP 1012 are implemented. This item remains unresolved pending review of licensee action to further define the event reporting process (289/88-18-01).
2.4 Valve Line-Up/Startup Procedure Review The inspector conducted a post-startup review of the completed valve line-ups that are accomplished prior to plant startup. The licensee conducted valve line-ups of all systems using a single operator and, additionally, the Quality Assurance Department performed independent valve line-ups on selected systems. Finally, the operations department conducted management verification of other selected systems, such as make-up, decay heat, containment integrity, and emergency diesel genera-tors (EDG's) to provide additional assurance the safety systems were properly aligned for plant operation The inspectors witr.essed several of the operations management verifica-tions on several systems. These included EDG's, Engineered Safeguards Actuation Systems (ESAS) and Heat Sink Protection Systems (HSPS), con-tainment integrity, and Emergency Feedwater Systems (EFW). Some discre-pancies were noted. The problems on the diesel generator line-up re-suited in the inspector identifying an apparent violation of NRC require-i ments due to four valves in the system not being on the valve line-u This was documented by the team inspection in NRC Inspection Report N /88-1 Some problems were also noted in the walkdown of the containment associ-l ated with the verification of containment integrit Tti inspector wit-nessed management's verification of valve line-up integrity in accordance with Operating Procedure (0P) 1101-3, Revision 47, "Containment Integrity and Access Limits." During the valve line-up check, the inspector noted a discrepancy in the identification of two penetrations in the inter-i mediate building (Penetration Nos. 421 and 422). The licensee determined
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that the procedure was correct, but the penetrations were incorrectly l identified. This error was corrected promptl The inspector found a valve in tha intermediate building, (322-foot ele-vation) attached to the penetration No. 421, which was in the correct position, but was not identified in the procedure or on the system draw-ing. The licensee assessed the significance of this discrepancy and l
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determined that the valve was a part of penetration pressurization, a non-safety-related system which was not part of the containment integrit The licensee could not find any installation record; however, it was determined that it was temporarily installed to supply air to valve RB-V-7. As a corrective action, the valve was removed. Overall, the valve line-up was performed in accordance with the procedure and the inspector found the procedure adequat Also, the inspector noticed a blue tag hanging on one of the containment isolation valves. Following review of the Switching and Tagging Log, it was verified by the licensee that the tag was cleared by the previous team which conducted the valve line-up, but an error was made in not removing it. This problem was corrected immediatel Further, on August 17, 1988, the inspector observed a red tag (No. 686)
on an instrument air valve, IA-V-535, in the intermediate building (322-foot elevation) in the vicinity of RB-V- The tag was dated February 1981. The inspector reviewed the Switching and Tagging Log and deter-mined that the tag w:.s not on the active list. OP 1104-25, Revision 56,
"Instrument and Control Air System," reflected the proper status of the valve (closed). However, the licensee determined that the valve was not needed due to past modifications. Therefore, after verifying the correct position of the valve, a cap was installed and a Procedure Change Request (PCR) was initiated to reflect the cap installation. The licensee ac-knowledged that an error was made by not identifying this red tag during the valve line-up verificatio The inspector also found loose red tags in the reactor building, as well as the auxiliary building The inspector reviewed Administrative Procedure (AP) No. 1002, Revision 55, dated June 27, 1988, "Rules for the Protection of Employees Working
- on Electrical and Mechanical Apparatus." The procedure did not require accountability for red and blue tags once they are removed. The icensee was aware of these findings. Switching and tagging will conti m to be
, reviewed routinely by the resident inspector Additionally, the inspector reviewed completed startup procedures and valve line-ups for the folinwing plant systems:
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Operations Procedure (0P) 1102-2, Revision 90, dated August 10, 1988,
! "Plant Startup," (which included independent verification of safety I systems per Administrative Procedure (AP) 1067);
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OP 1103-5, Revision 38, dated July 21, 1988, "Pressurizer Operation;"
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OP 1104-1, Revision 20, dated April 22, 1988, "Core Flooding System;"
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OP 1104-2, Revision 09, dated August 31, 1988, "Make-Up and Purifi-
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OP 1104-5, Revision 29, dated August 8, 1988, "Reactor Building Spray System;"
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OP 1104-25, Revision 56, dated August 5, 1988, "Instrument and Con-trol Air System;"
Generally, the system startup portion of the procedures were signed off correctly and documented. Exceptions and deficiencies (E&D's) that were noted during performance of the valve line-ups were dispositioned in a satisfactory manner for the valve line-ups reviewed. The inspector con-cluded that operations procedures for startup were properly implemented and controlled. The inspector had no safety concerns on these issue .5 Reactor Coolant Pump Trip, Reactor Protection System / Heat Sink Protection System Actuation On Saturday, August 13, 1988, during hot shutdown with the reactor sub-critical and during final testing of the Integrated Control System /Non- t Nuclear Instrumentation (ICS/NNI) power system upgrade modification, a reportable event occurred. Just prior to 11:30 a.m., the "AUT0" sub-power feed to the ICS/NNI system was de-energized with the "HAND" sub-power feed energized. At 11:31 a.m., test personnel energized "AUT0" sub power and all four operating reactor coolant pumps (RCP's) trippe This was because the sequence of "AUT0" energization satisfied the seal cooling-seal injection int ' lock tripping the RCP's. Additionally, the Heat Sink Protection System (HSPS) actuated on trip of all four RCP' This trip of RCP's and the HSPS actuation was a normal occurrenc '
With safety rod groups full out of the core, no reactor trip occurred
! (initially thought to be off-normal by operations personnel). At 11:46 a.m., the licensee started one RCP and the Reactor Protection System i (RPS) actuated. The safety rod groups were inserted automatically into the core. Emergency feedwater (EFW) pumps started because of the HSPS actuation but no water injected to the steam generator because water level was above the low level limit setting for feedwater contro The RPS actuation event was reported to NRC Operations Center per 10 CFR l 50.72 b.2(u).
As corrective action, the licensee revised their test procedure and emergency procedures to prevent the RCP trip on "AUT0" power re-energi-
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zation. The licensee satisfactorily retested this sequence prior to criticality.
l The licensee also reviewed the RPS lack of actuation and RPS/HSPS actu-
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ations noted above. They concluded that the actuation systems functioned l as expected with the existing zero power flux indication. They also i reviewed current surveillance data for the RPS to verify proper response.
j With these actions complete and no discrepancies, the licensee took the reactor critical the next day.
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By Monday, August 15, 1988, the licensee also revised (final typed ver-sion) applicable emergency procedures to address the proper sequence of energization of ICS/NNI "AUT0" sub-feed circuits to preclude the trip of RCP's at powe The NRC shift inspectors concurrently reviewed licensee actions prior to criticality to assure .that the RPS system responded properly and that a retest demonstrated a proper sequence of "AUT0" sub-feed re-energiza-tion to preclude the trip of RCP' Licensee formal review and documen-tation of the event would occur using the Licensee Event Reporting Pro- 1 cess in accordance with 10 CFR 50.7 .
The NRC senior resident inspector and NRC/NRR Project Manager further reviewed the event to get a better understanding of RPS system response '
for the plant conditions between 11:30 a.m. and 11:46 a.m. on August 13, 1988. They reviewed selected sections of the following document Multi-Discipline Review of Level II Log Entries for the RCP Trip of August 13, 1988
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RCP Monitor Calibration Data as of August 13, 1988, for Channels A, B, C, 0, Section 8.6 of Surveillance Procedure (SP) 1303-4.1, Revision 58, dated August 12, 1988, "Reactor Protection System" l
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Test Procedure (TP) 349/7, dated August 13, 1988, "Functional Test-ing of ICS Control Loops on Loss of Power at Hot Shutdown"
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Technical Specifications (TS), page 2-9, "Reactor Penetration System Trip Setting Limits
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Emergency Procedure (EP) 1202-40, "Loss of ICS Hand and Auto Power" ,
and EP 1202-42 "Total or Partial Loss of ICS/NNI Autt Power" l l
The inspector reviewed TP 349/7, which initiated the sequence of events '
at 11:30 a.m. The procedure was adequate to confirm expected results on loss of "AUT0" ICS/NNI power which were: controllers shifted to hand; redundant instrumentation (pcwered by "HAND" power) remained energized; <
expected loss of power to instruments powered by "AUT0" power; and, the ,
existing emergency procedures accurately lists these expected event L The licensee's review of the procedure did rot anticipate the need for a special sequence in which to re-energize auto power to preclude an RCP tri The inspector considered this feature a subtle design aspect of the system that reasonably would not be discovered by procedure revie The intent of test procedure was met in that the unexpected was identi-fled prior to power operation, which certainly would have caused a plant trip if the test had been accomplished at powe The inspector reviewed the proper sequence for re-energizing "AUT0" powe ,
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The "AUT0" power has reveral sub-feed circuits. Two of these sub-feed circuits power instruments that are for the make-up and purification (MU)
system and for the intemediate closed cycle cooling (IC) system. Cer-tain MU and IC instruments satisfy an interlock for proper RCP operatio If MU power is restored before IC power, a RCP interlock will function to trip a RCP, signifying that there is no (MU) seal injection or thermal barrier cooling to the RCP seals (reactor system pressure boundary).
The licensee's retest of TP 349/7 on August 13, 1988, successfully de-monstrated the re-energization of "AUT0" power and the MU and IC sub-feeds without tripping the RCP's. The licensee properly incorporated this sequence into their emergency procedure The inspector reviewed why the RP3 system did not actuate at 11:30 when all four RCP's trippe The nuclear power based on pump monitor reactor trip instrumentation uses a variaole setting bistable (or electronic switch). The two compared signals are nuclear power or flux (0-125 percent or 0-10 volts (VDC)) and flow (0-100 percent or 0-10 VOC). The power range nuclear instrumentation supplies the flux signal, while the flow circuitry con-verts a digital (any combination of four RCP on/off indications) to an analog signal 0-10 VO The instrumentation produces a reactor trip signai on the following conditions per T (1) Loss of two RCP's in one reactor coolant (RC) loop (2) Loss of one or two RCP's during two pump operation (3) Fifty-five percent high power trip with one RCP operating in each loop SP 1303-4.1 weekly checks these settings. This test data for "A" and
"D" channels were takea August 12, 1988. The test data for "B" and "C" were taken on August 13, 198 For the plant conditions reactor power (NI) produced close to O percent or 0 VDC signal at the above-noted comparator. When the RCP's tripped, a close to 0 VDC signal wa!, also sent to the comparator. A difference of about 0.08 VDC is needed to trip the bistable. At the low voltage, apparently the "D" RPS channel had a substantial difference (at the 0 volt setting) to cause a channel actuation. The "A" and "C" channels apparently did not develop enough of a difference to trip the bistabl The "B" channel was in test or bypass and did not actuate. At 11:46 a.m.,
when a RCP was started, apparently enough of a fluctuating voltage dif-ference (at 0 volts) was developed to cause the RPS actuation. The in-spector tentatively concluded that the RPS responded properl .
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The licensee will be submitting a Licensee Event Report (LER) on this event. Further NRC Region I review of this event will occur at that time (289/88-LO-04).
The licensee's internal review of this event also identified a need to review procedural guidance to operator on loss of RCP's with or without a RPS actuation (yet to be completed).
2.6 (Closed) Unresolved Item (289/88-13-06): Pressurizer Cooldown Event The inspector reviewed Licensee Event Report (LER)88-002, dated July 19, 1988, for the event on June 19, 1988, "Pressurizer Level and Cooldown Rate Exceeded Due to Inadequate Test Procedure." On June 19, 1988, dur-ing the shutdown phase of the 7R refueling outage, the licensee performed the low pressure injection (LPI) test in accordance with Surveillance Procedure (SP) 1303-11.54, Revision 5. The test required each of the two decay heat pumps to deliver equal to or more than 3,000 gallons per minute (gpm) flow. The test data confirmed the required flow for each i
pump. However, during the test on both pumps, the pressurizer cooldown rate exceeded the technical specifications (TS) limit of 100 F in any one hour (TS 3.1.2.3). Also exceeded was the 220 inches Limiting Condi- i tion of Operations (LCO) on pressurizer level with the "B" make-up pump in operation and the Reactor Coolant System (RCS) temperature less than 275 F (TS 3.1.12.3) which created the condition of potential over pres-surization of the RCS at low terrperatur The licensee providrd an assessment of the safety consequences of this event and determined that, in the first instance, the thernal stresses induced due to temperature change were within the bounds of the fatigue criteria and, in the second case, the operable power-operated relief valve (PORV) would have provided over pressure protection, In order to prevent recurrence of these events, the licensee planned to conduct a thorough review of the surveillance procedure and revise it as necessary prior to the 8R refueling outag The inspector reviewed the related unresolved item (289/88-13-06) for this event by reviewing the past test data and noted the followin Step 8.1.11(b) requires three simulta m ous readings of the RCS
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pressure and LPI flow. *n reality, the readings are taken in con-
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secutive order.
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The flow data is taken oa either or both the console or RSP flow
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meters. The procedure is not specific.
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The acceptance of data logger points under step 8.1.12 is not con-sistent. Sometimes they are written out as "normal," "high," and
"low" or "signed of f."
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The flow instruments used are not always identified as required under step 8.1.1 The licensee acknowledged these findings and they stated that the dis-crepancies will be addressed during the planned revision of the procedur The inspector also reviewed the LER for technical adequacy, as well as compliance format as described in 10 CFR 50.73. He determined that the LER was well written and adequately addressed all the related technical issues. The event was identified and reported as required and corrective actions appear to be acceptable pending review of the procedure revisio The above-noted items concerning pressurizer level and temperature represent an apparent violation of Technical Specification Sections 3.1.12.3 and 3.1.2.3. In their LER, the licensee acknowiedged that the above-noted limits were probably exceeded in past tests also. Further, the inspector determined that corrective actions from previous violations concerning procedure adequacy could reasonably have prevented this type of problem if more attention to detail had been provided during tne past tests and biennial procedure reviews. Accordingly, in accordance with 10 CFR 2, Appendix C, Section V.G.1, this violation is not considered
"licensee identified" (289/88-18-02).
The LER provided adequate details on the planned long-term corrective actions. Therefore, the inspector determined that no additional licensee response was necessary, lhis item will remain open pending further review of the licensee's procedural corrective actions (289/88-18-02). The previous unresolved item opened to track this event (289/88-13-06) is close .7 Operations Summary Plant operations activities were generally conducted in an acceptable manne Control of startup activities, use of procedures, valve line-ups, l and surveillance activities were accomplished in a manner conducive to safe plant operation. Some areas appear to need improvemen The logkeeping and event review process appear cumbersome and not well defined. Upcoming procedure changes are planned to correct this situ-ation. Procedures that control use of tags appear to need more controls
- to assure proper disposition of tags. The licensee needs to revise a surveillance procedure to prevent the technical specification violations I associated with pressurizer level and temperature limits during the low l
pressure injection test.
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3.0 Ew ;pment Oper 4 *s ; sinter.ar. o/5 ave 111ance 3.1 Criteria /'-
During this % aa, th .c ;ectors reviewed unresolved items related to g ident..ied in the previous inspection report (NRC Inspectiot , , 20-2A 't 13), as well as selected items in-volving maintena...:.., - tion, e111ance, and plant modification to support plant star-3.2 Letdown Sample Valve Oper,. .ity Valve CA-V-13 is a sample point on the letdown system and is frequently used to draw samples of reactor coolant for analysis. During the plant startup phase, the valve malfunctioned several times. Job Ticket N CL-416 was issued. The valve was re-worked three times before making it operable. The inspector reviewed the job ticket and maintenance logs and discussed the troubleshooting process with maintenance and engineer-ing personnel. The root cause of the problem, however, was traced to the improperly tightened gland on the valve stem and this was not iden-tified until the third time the valve was taken out of service. Appar-ently, previously post-maintenance tests were acceptably conducted with an incomplete correction of the problem. The licensee's troubleshooting procedure 1420-LTQ-1, Revision 10, provided a reasonable approach to troubleshooting Limitorque operator problems, but it could be enhanced to address the gland nut tightening check. The licensee representative stated that they du plan procedural erhancements and training as feedback to technicians who normally work in this are During the troubleshooting, the inspector detern.ined that the Limitorque switch setting was misread and, therefore, mis-adjusted. The Limitorque switch adjustment procedure 1420-LTQ-2, Revision 10, did not provide details to assist craf ts personnel during switch adjustment. The 11cen-see representative also planned enhancements to this procedure as wel However, the inspector also reviewed test data on several Limitorque valves that were inspected during the 7R refueling outage and determined that the licensee had adequately implemented procedures and properly documented test data as well as corrected the known deficiencies identi-fied. Overall, the licensee's performance was found to be very good in this area and the performance problem on CA-V-13 was an isolated cas .3 Condensate Pump Discharge Piping Support The inspector found three of the four bolts loose and one broken on the condensate pump discharge piping support (C0H-167). The system is sels-mic class III and not safety related; however, it could patentially challenge the primary system of the plant. The licensee performed an engineering evaluation (5320-88-3066), dated August 11, 1988 and deter-i
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mined that the present condition did not result in an unsafe conditio The licensee, however, planned to take appropriate corrective actions at a future date. The inspector did not have any further concer .4 Safety-Related Check Valve Inservice Testing On July 21, 1988, the resident inspector, along with the NRC/NRR repre-sentative, witnessed the inspection and testing of the check valve OH-V-14A. The inspection was done to determine full flow operability. No adverse condition was found. This valve, among others, is the subject of an inservice testing (IST) relief request by the licensee to inspect the check valves on a ten year frequency (see NRC Inspection Report N /88-13). Any further actions on IST will be determined by the NRC/NRR at a future dat .5 Two-Hour Back-Up Emergency Feedwater Air Compressor Surveillance During the last operating cycle, cycle 6, the licensee installed an air compre<,sor to supply charging air for both banks of back-up air bottle These bottles were installed to provide a safety grade, seismic quality air supply for operation of control valves for the emergency feedwater (EFW) air-operated valves. The inspector previously had reviewed the installation of the compressor and resolved the question of air quality, but a question remained concerning the long-term verifiertion of a qual-ity dry air suppl Two operations surveillances were accomplished to verify quality ai The first, OPS-3356, accomplished on an eighteen-month basis verifies that air with the proper moisture content is supplied to the air bottle A dew point of less than -60 F is require The dew point previously was verified during the initial test and this operations surveillance should provide an appropriate air moisture check at a frequency that would reveal any problems with the compressor or air
dryers.
l Additionally, an operations surveillance, OPS-5330, schedules the per-
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formance of Enclosure II to OP 1104-25. This surveillance checked the
- capability of each air bottle bank to cycle MS-V-6 and the four EF-V-30
- valves. This test was completed satisfactorily for the first time in
, accordance with this procedure on August 9, 1988. No problems were noted.
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The inspector concluded that appropriate surveillance will be accomp-Itshed per OPS-S330 and 5356 to assure proper air quality and operation
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of the two-hour back-up air charging compressor and the respective bottle banks.
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3.6 Reactor Building Inspection On August 5, 1988, the inspectors toured the reactor building (RB) and had the following finding ,
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Overall housekeeping, including the work areas, was very goo [
Throughout the outage period, licensee management emphasized good housekeeping practices and conducted frequent walkdown The fire extinguishers were inspected and properly mounted, f
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Some weaknesses were observed in the material condition. For ex-ample, the inspectors noticed the conduit support for AH-V-1B was ,
loose on column C-102, the handles on valves FW-V-1327 and 1328 were ;
missing, the bracket on the "D" ring for valve DH-V-488 was loose, and the electrical conduit on junction box T-164 was loose. These deficiencies were discussed with the licensee and maintenance re-quests required to correct them were prepared. These deficiencies ;
did not present major safety concerns; however, the licensee ac- ;
knowledged these weaknesses and plar.ned to provide necessary guid-ance on assessing plant material conditions, as well as strengthen-ing the current management walkdowns. The inspec. tors will reassess "
material conditions during future walkdown .7 Unresolved Item 289_/_88-13-03):
8 pressurizer Relief Valvf Tailpipe (Closed)TogeBolts Support
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During the inspection of the pressurizer relief valve support PR-32 on June 29, 1988, the inspector found three of the four bolts were loose
- and the associated jam nuts for these bolts were hand tightened. Subse-
- quently, the licensee prepared an engineering evaluation (5563-88-0207)
on August 4, 1988, to assess the safety significance. The loose bolts on PR-32 allowed more "play" for movement because of varying dynamic j forces and they did not affect the support function. These bolts and
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the bolts on an adjacent support, PR-33, were re-torqued. This item was, therefore, closed. The inspector determined that the engineering evalu- i
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However, on August 4,1988, the inspector reviewed Job Ticket (JT) N CS-956 issued for the re-torquing activity. The JT was initiated by !
j plant maintenance on July 16, 1988, to torque the bolts on the support ,
t (PR-32) for the primary code safety relief valve (RC-RV-1A). The bolts :
I were torqued on July 21, 1988, in accordance with the specified, but generic, torquing procedure 1410-Y-72. The work activity was reviewed .
and approved by the maintenance supervisor on July 22, 1988, as docu- '
mented in the J "
Also, on At. gust 4, 1938, plant engineering provided the inspector a special instruction (G/C/TMI-1CS/ 16471), dated July 14, 1988, from the architect engineer, Gilbert / Commonwealth. This instruction provided ,
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guidance on torquing the support bolt, which was different from what was used in the JT. The support bolts were re-torqued under the same JT number on July 29, 1988, in accordance with the new guidance. However, the inspector noted that the change of scope for this JT was not docu-mented, reviewed, and approved, as required by' corrective maintenance procedure (CHp) 1407-1, Revision 32,' paragraph 6.2.1.2. This is an ap-parent violation of TS Section 6.8.2, which states that any substantive changes to the established procedure shall be reviewed and approved prior to implementation (289/88-18-03). ,
Subsequent to the inspector's identification of this violation, the Quality Assurance Department issued Quality Deficiency Report (QOR)
JBM-043-88, dated August 22, 1988. This addressed the inspector's find-ings and described several other examples where maintenance activities were performed without obtaining appropr' ate approvals on various engi-neering evaluations. It appeared to the inspector that a number of maintenance activities were conducted based on verbal communications with engineerin .8 Equipment Operability Summary The 7R refueling outage concluded during this inspection period. The trouble-free plant startup, followed by satisfactory operation to date, clearly indicated good overall performance in this area; however, one -
violation was identified. The licensee's response in correcting the startup-related items identified in the NRC Inspection Report No. 50-
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289/88-13 was adequate and timely. Long-torm corrective actions in the areas noted above are warranted to further strengthen their existing
- program .0 Engineering Support 4.1 Criteria / Scope of Review i
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The inspectors reviewed selected licensee activities which required en-i gineering support to assure that this support for these licensee activi-l ties was timely and adequate for the activity involved. The inspectors I reviewed various modification packages, including system design descrip-I tions and safety evaluations, and witnessed the licensee engineering staff performing core testing activities associated with plant startup.
i A detailed review of these activities is provided below.
i 4.2 Diesel _ Cooling Water Temperature Instrumentation Modification
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On July 29, 1988, the inspector found the emergency diesel generator I
(EDG) "B" Jacket coolant inlet temperature gauge not functioning. Nor-mally, it indicates approximately 120 F. Plant maintenance initiated a job ticket to repair / replace the gauge. In reviewing the calibration records for this instrument, the inspector noted that the gauge was in-stalled under a "blanket" engineering modification and was calibrated i
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in November 1987 following the modification. The gauge has an annual calibration frequency; but, it was not included in SP 1301-8.E and, therefore, potentially could remain uncalibrated. After reviewing the Administrative Procedure PEP-2, Revision 3, "Plant Modification and Re-placement-in-Kind Applicability / Scope," the inspector determined that -
the procedure does not provide specific guidance to assure that all the documents affected by a modification are revised. The licensee acknowl-edged the finding and promptly initiated two PCR's to revise SP 1302-8.2, as well as PEP 2. The inspector considered this an isolated case;
) therefore, no further review is warranted.
j 4.3 Fuel Handling Bridge Modifications In preparation for the cycle 7R refueling outage, a series of modifica-tions were made to the main and auxiliary fuel handling equipment. These modifications are designed to increase system speed of operation, improve
- system reliability and permit the system to handle Mark B-4 and B-5 con-trol elements. To accomplish this, the following was upgrade The existing hydraulic rod drive system was replaced with a hoist-driven mechanical rod drive system.
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The control rod mast was modified for handling Mark B-4 and B-5 assemblie The existing Dillon load Sensing Systems on both the main and auxiliary fuel handling bridges was replaced with a sensotec digital syste Fuel assembly grapples on both bridges were replaced with grapples capable of handling a B-4 fuel assembly with either a B-4 or B-5 control component installe The existing control console on the neain fuel handling bridge was replaced with a new console equipped with quick disconnects from the Motor Control Center (MCC) to allow removal of the console from the bridg A television positioning system was installed on the main and auxiliary fuel handling bridge An inching positioning system with programmable geared limit switches was installed on both the fuel assembly and control rod masts on the main fuel handling bridge Through discussions with licensee representatives, observations of in-stallation and testing activities and review of supporting documentation (refer to Attachment 1), the inspector assessed the effectiveness of the licensee's management controls, as promulgated in the licensee's Opera-tional Quality Assurance Plan, in completing these modifications. The
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inspector determined that a detailed evaluation was performed as required by 10 CFR 50.59 to assess the impact on plant safety prior to beginning the system modifications. Through review of this safety evaluation, the inspector determined that the evaluation was thorough and adequately addressed the criteria of 10 CFR 50.5 Through examination of the installation procedures, the inspector deter-mined that the licensee's Quality Assurance Department completed review of these documents and identified hold and witness points within the procedures. By witnessing various aspects in performing the modification, the inspector confirmed the involvement of quality assurance personnel during the installation and testing phase In reviewing the documentation supporting the functional testing of the '
completed modification, the inspector concluded that revised testing procedures had received the appropriate level of cross-displinary reviews through the Test Approval Group prior to test implementatio t The inspector determined that field questionnaires generated during the ,
installation and testing phase were resolved in a timely manne Overall, the inspector concluded that there was effective coordination among the various departments within the licensee's organization; i.e, Startup and Test, Quality Assurance, Technical Functions. and Raalologi- ,
cal Controls, to provide independent reviews and provide job coverage l to assure that the modification were completed in accordance with the relevant procedure No violations of regulatory requirements were identifie .4 Cycle 7 Fuel Lead and Physics Testing
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4. Reload Safety Evaluation Reviews in Preparation for Cycle 7
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Refueling and Startup In preparation for cycle 7 fuel reloading activities and start-i up, the inspector reviewed selected refueling and operating [
l procedures to verify incorporation of the requirements of Lic- '
i ense Amendment No. 142 into these procedures. No discrepancies '
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were note ;
( Of the 177 fuel assemblies comprising the Unit I reactor core, ;
j Cycle 7 will contain thirty-six fresh Mark B4Z fuel assemblies ;
- with a 3.63 weight percent enrichment. Since this fresh fuel has a slightly higher U-235 enrichment than previous fuel, '
l there will be a slight increase in core life time from ap-l proximately 425 effective full power days (EFPD) to approxi- ,
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mately 445 EFPD.
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l The safety evaluation performed by the NRC staff to support
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the core design changes and this cycle's operation concludes that the reload and the associated modified technical specifi-cations are acceptable and, accordingly, the NRC staff issued i License Amendment No. 14 .4.2 Initial Criticality Initial criticality of cycle 7 was achieved on August 14, 1988, at 2:15 p.m., with a Reactor Coolant System (RCS) bore con-centration of 1,636 parts per million (ppm) and group / posi-tion at 40 percent withdrawn. The predicted boron concentra-tion, based on the same group 7 position, is 1,577 ppm. The measured deviation from prediction is, therefore, 1,636 ppm -
1,577 ppm = 69 ppm. This result is within the acceptance cri- l teria of 1 100 pp l 4.4.3 All Rods Out ( AR0), Critical Boron Concentration l The inshe tor NViewed test data taken to determine the boron concentration required to achieve reactor criticality at hot I zero power when all control rods are full out of the cor l The measured value of 1,692 parts per million (ppm) met the acceptance criteria of the predicted value of 1,636 1 100 pp l 4.4.4 Isothermal Temperature Coefficient (ITC)
Through discussions with licensee representatives and review of test data, the inspector determined that the licensee meas-ured ITC by sequentially performing a 5 F heatup, a 10 F cool- l down, and then a 5 F heatup. The licensee's test result was !
based on the cooldown test data. Results of the two heatup I tests were used to verify the accuracy of the cooldown test data at hot zero power with all control rod assemblies with-draw l The measured ITC of 2.41 pcm/F* met the acceptance criteria of the predicted value of 2.8714 pcm/ The corresponding moderator temperature coefficient (MTC) was determined to be 4.09 pcm/F. The inspector determined the measured MTC met the technical specification limit of being less than 5.0 pcm/ delta K/K
- pcm is per cent millirho = 10
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4. Control Rod Worth Measurement The licensee measured the regulating group rod worth in accor-dance with Refueling Procedure (RF) 1550-02. The following results were obtaine c Predicted Value Measured Valve
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Group 7 978 1 15% 925 Group 6 971 1 15% 924 Group 5 1,208 1 15% 1,220 Integral Rod Worths 3,157 1 10% 3,070 532 F Groups 5, 6, 7 Test results were within acceptance criteri The corresponding differential boron worth as derived from this test was 9.24 pcm/ ppm B. This value agreed well with the pre-dicted value of 8.74 pcm/ ppm B and was within the acceptance criteria of i 15 percen . Core Power Distribution Verification The detailed core power distribution at the 75 percent power plateau was measured by the licensee per procedure RF 1550-08,
"Core F'ower Distribution Verification." The inspector notsd the following result The measured quadrant power tilt was 0.31 percent, which was within the TS 3.5.2.4 limit of 4.12 percen The measured radial peaking factor for each fuel assembly was consistent with the analytically predicted valu The comparison of the highest measured radial peaking
+ factor (1.293) at core location L-13 reasonably agreed with the predicted value of 1.29 The measured total peaking factor in each fuel assembly also consistently agreed with the predicted value. The highest measured total peaking factor (1.533) at core location L-13 agreed well with the predicted value of 1.57 The measured linear heat rate at each axial location was within the TS 3.5.2.7 limi All results were acceptabl . _ _ _ _ _ _ _ _ _ ._ _ _ _ _ _ _ _ _ _ _
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4. Power Imbalance Detector Correlation Test The inspector witnessed the performance of the Power Imbalance Detector Correlation Test and dciermined the test was performed in accordance with procedure RF 1550-04, Revision 11. This test established the relationship between the indicated out-of-core (power range nuclear instrumentation) offset at the 75 percent power plateau. A reasonably goort linear relation-ship for all four power range channels (NI's 5-8) was observe The scaled difference amplifier gain factor or 3.684 that was calculated during cycle 6 physics testing was determined to be appropriate for cycle 7 core conditions. Accordingly, no changes needed to be made to the inputs of the Reactor Projec-tion System (RPS) for this variabl .5 (Closed) Unresolved Item (289/88-08-01): RC-V-28 Environmental Qualifi-cation The licensee identified a potential environmental qualification (EQ)
problem with RC-V-28 and committed to upgrade the motor during the 7R outage. Subsequently, the motor was replaced by a qualified motor and the valve actuator upgraded to EQ status. This action was determined by the inspector to be adequate to resolve the concern with RC-V-28 and 289/88-08-01 is close Subsequently, the licensee also determined that the control cable for RC-V-28 was not IE qualified. The control cable was run in a raceway with other non-1E cabling. The licenses prepared a justification for continued operation (JCO) with the RC-V-18 control cabling in a non-1E status. The JC0 was reviewed by the inspector and determined to ade-quately address the concerns for the control cable. The licensee was able to determine by walkdown and, also, some modification that the raceway in question did meet applicable seismic qualification criteri Also, the licensee determined that adjacent circuits were protected by proper protective devices which would isolate those circuits in case of faults and, therefore, would protect the safety circuits (RC-V-28). The inspector reviewed the JCO, Memorandum No. 5350-88-341, dated August 8, 1988, and determined that the licensee adequately addressed the safety concerns for RC-V-28 control cable. This memorandum was also reviewed by a NRC Region I specialist inspector and documented in NRC Inspection Report No. 50-289/88-16. The licensee committed to upgrade the cabling during the 8R outage. The inspector had no other concerns on this issu .6 (Closed) Unresolved (289/88-13-05): Borated Water Storage Tank Vortex,ing On July 22, 1988, the licensee completed an evaluation of Preliminary Safety Concern (PSC) No.88-003. This PSC identified a potential problem with the borated water storage tank (BWST) level at which manual action is taken to switch from the injection mode to the reci'tulation mode
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following a large break loss of coolant accident (LBLOCA). This level had previously been established at 3 feet above the bottom of the tan PSC No.88-003 postulated that vortices may form in the low pressure in-jection (LPI) line from the BWST. These vortices could possibly have caused air binding in the LPI pumps and loss of ability to cool the core on a LBLOC The licensee subsequently resolved the PSC via Safety Evaluation (SE)
No. 000241-001, which revised the low-low level alarm setpoint to 6 feet, 4 inches above the bottom of the tank. By procedure, the control room operators would then commence switch-over to the recirculation mode and !
time would be available to complete the switch-over prior to the forma-tion of vortices in the supply line. This change in switch-over level also necessitated changing the maximum flow from the building spray (BS) i pumps after the switch-over due to a reduced net positive suction head in the RB sump (water level).
The inspector reviewed the data provided in the PSC and the SE and con-cluded that a proper evaluation was completed. The data provided in the ,
PSC and the calculation in the SE provided sufficient information to l conclude that the BWST low-low level alarm could safely be raised to the new setpoint. The resulting reduction in spray flow would not have a significant impact on todine removal, sump pH, or RB temperatere profile during the LBLOCA transient. The new low-low level alarm setpoint pro-vides for instrument error, operator action time, and RB sump suction valve opening, which was not previously considered. The only affect of this new level was requiring a low RB spray pump flo .
The inspector concluded that the licensee adequately evaluated the change to the BWST low-low level setpoint and that the evaluation was completed :
in a timely manne '
Communication with NRC staff was good and staff inquiries were disposi-tioned adequately. No safety concerns were identified by the inspectors as a result of this change and this unresolved item (289/88-13-05) is close .7 (Closed) Unresolved Item (289/88-13-07): Control Building Ventilation" System Booster Fans Modification
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The modification involved in increasing the number of fan blades to boost !
the air flow to the second floor of the control buildin The flow in-crease was expected from 6,400 standard cubic feet per minute (sefm) to 9,500 scfm. The actual flow following the modification was 7,400 scfm (within 10 percent of the 9,500 scfm). The Final Safety Analysis Report (FSAR), Section 9-8, Figure 9.8-1, specified 8,074 scfm. The licensee planned to do additional modifications at a later date. The inspector expressed concerns about the impact on the cooling of the second floor i due to reduced air flo l
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The licensee, then, provided an engineering evaluation, 3310-88-0121, dated August 4, 1988, which addressed that the slightly increased air flow combined with the relocation of some equipment, had a net offect of reduced heat loa The inspector did not have any further comments and determined that the licensee had adequately addressed the issu .8 Engineering Support Summary Generally, issues identified by the licensee or NRC staff that required engineering support were dispositioned in a satisfactory manner by lic-ensee engineering support personnel. Response to the BWST vortexing issue was timely and the evaluation addressed all relevant concern Self-identification of other problems such as RC-V-28 control cable was 1 noteworthy. A problem identified by the inspector in site engineering support for change modifications to the diesel water cooling system re-suited in a commitment to upgrade site procedures to correct apparent weaknesses in these procedure Low power physics test was properly conducted. Test data was within pre-dicted range. The nuclear engineers provided good support to operations during these activitie .0 Radiolugical Controls 5.1 Radiation Surveys On July 22, 1988, the inspector noticed twelve outdated radiation surveys posted at the control poin Similar conditions were observed at other locations during the early phase of the outage. The Radiation Field Operations corrected tl.a problem by implementing a "daily check" syste Since then, followup inspection did not identify similar occurrence The inspector found that the current radiation surveys were conducted properly and radiation work permits were issued based upon the current surveys; however, an error was made in distribution and posting. There was no concern regarding personnel exposur .2 Decontamination of Transfer Canal On August 2, 1988, following refueling, the licensee started decontamin-ation of the deep end of the fuel transfer canal. During the decontam-ination process, which involved use of a vacuum cleaner, the radiation level increased significantly and reached as high as 500 Rem / hour at one location on the vacuum cleaner housing. The licensee promptly took ap-propriate corrective actions. The licensee did not exceed any personnel exposure limits. Following the review of job activities, the inspector concluded that the job planning was done very well. The planning effort included pre-job review, direct supervision by the radiological personnel,
. _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
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i post-job review, as well as implementation of lessons learned while the
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vork activity was in progress. The licensee planned to consider differ-ent decontamination methods in this area for added safety in future evolutions of this typ l 5.3 (Closed) Unresolved Item (289/87-09-02): RM-A-5/15 Process Radiation j Monitor j
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l This item was opened due to incomplete licensee action for installation of RM-A-5/15 condenser off gas radiation monitor. Work that was incom- l
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plete at the conclusion of 6R outage included installation of the control j room recorder for the RM-A-5/15 gas channels and the flow rate recorder ,
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for off gas flow. The inspector verified that the recorder was installed and functioning properl ,
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Also a problem wts identified with moisture accumulation in the sampling j lines. The tubing that supplies the monitors from the main vacuum pump r discharge line and the drain piping for the monitors was re-designed to :
! alleviate this problem. Also, it was discovered that residual contamin- !
ation in the RM-A-15 monitor housing may have contributed to higher '
- readings in that detector. Both RM-A-5 and RM-A-15 are now indicating l within the same order of magnitude and within 10 percent of their average !
- readin This is a satisfactory condition for the very low radiation !
- level that these detectors measur [
l l The inspector concluded that licensee action to correct the RM-A-5/15 l
- anomalous reading and complete installation of the appropriate recorders !
was timely and adequat This iten is close (
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5.4 Radiological Controls Summary
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I Overall, the licensee had good radiological control practices in place.
i Posting of radiation zones, control of locked high radiation areas, pre- (
i and post-job reviews, implementation of lessons learned, as well as i
- radiological training for temporary and personnel throughout the 7R out- .
l age were effectiv j
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l 6.0 Exit Meetinj The inspectors di cussed the inspection scope and findings with licensee man- ,
agement weekly and at a final exit meeting on September 1,1988. Those per- !
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sonnel marked by an asterist in paragraph 1.3 were present at the final exit i meeting.
l The inspection results, as discussed at the neeting, are summarized in the l
- cover page of the inspection report. Licensee representatives did not indi-l cate that any of the subjects discussed contained proprietary or safeguards j information.
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Unresolved Items are matters about which more information is required in order to ascertain whether they are acceptable, violations, or deviation Unre-solved items discussed during the exit meeting are addressed in Section 2, 3, 4, and 5.
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ATTACHMENT 1 NRC INSPECT 10N REPORT NO. 50-289/88-18 ff,TIVITIESREVIEWED Plant Oper4tions
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Control room operatio.n caring regular and back shif t hours, including fre-quent observation of xtivities in progress and periodic review of selected sections of the shif t toreman's log and control room operator's log and selecteo sections of rther control room daily log Areas outside the control roo Selected licensae planning meeting Various heatup and startup activities and events as desciibed within the body of the repor During this inspection period, the inspectors conducted direct inspections du-ing the fcilowing back shift hour Day /Date (time Saturday, July 16, 1988 ?:00 a.m. - 10:00 Wednesday, July 20, 1988 10:30 p.m. - 11:30 p.m.
- Friday, July 22, 1988 4
- 00 a.m. - 7:00 Saturday, July 30, 1988 11:00 p.m. - 12:00 Midnight Monday, August 1, 1988 4:00 p.m. - 8:00 Saturday, August 6, 1988 8:45 a.m. - 1:30 Sunday, August 7, 1988 8:00 :00 Noon Friday, August 12, 1988 4 00 p.m. - 12:00 Midnight -
Saturday, August 13, 1988 8:30 a.m. - 12:00 Midnight Sunday, August 14, 1906 4:00 a.m. - 11:15 Tuasday, August id, 1988 4:00 a.m. - 7:00 Tuesday, August 16, 1988 4:00 p.m. - 11:15 Wednesday, August 17, 1983 6:15 a.m. - 12:00 Midnight Thursday, August 18, 1988 4:00 p.m. - 12:00 Midnight i Maintenance / Surveillance
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The maintenance anG surveillance activities reviewed are described ir. the appropriate sectioris of this repor Fuel Handli M ystem Modifications - Docup nts Reviewed
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Safety Evaluation. TI-MM-412232-002, Revision 2, "Installation Specification Fuel Handitng Bridge Equipment Upgrario"
b.... , Attachment 1 2
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Fire Hazard Analysis, 412231.-001, Revision 1 ,
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TP 438/1, Revision 1, "Function Test of Console Controls and Interlocks for the Main Fuel Handling Bridge"
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Incomplete Work List
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Document Package for Job Order No, AHA-G1232, "Plant Modification No. 80958"
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SR-PP-920, Revision 2, issued April 29, 1988, Assembly Procedure for Control Rod Mast Modification
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ALARA Review 88-03-05 in support of Main / Auxiliary Fuel Handling Bridge Up-grade Inside Reactor Building
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Connector Termination Schedules
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SR-PP-941, Revision 0, issued May 25, 1988, Installation Procedure to Install Bridge Positioning Television System
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VM-TM-0703, Instruction Manual, Fuel Handling Equipment Control Red Mast Modification
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Instrument Calibration Data Sheets for Sensotec load Indicating Cells, MTX 105. Roll-Up Field Change Notice for Fuel Handline Bridge Equipment Upgrade (C0 52479) '
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Controlled copies of (Stearns-Rogers) drawings related to Fuel Handling Bridge Equipment Upgrades (Work Authorization No. A25A-30232)
Reactor Coolant System (R_CS) Leak _ Rate 3 The inspector selectively reviewed RCS leak rate data for the past inspection period. The inspector independently crIculated certain RCS leek rate data reviewed using licensee input data and a generic NRC "BASIC" computer program "RCSLK9" as specified in NUREG 1107. Licensee (L) and NRC (N) data are tabulated belo .
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t Attachment 1 3 TABLE RCS LEAK RATE DATA All Values GPM
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'DATE7 TIME MPlG1107) CORRfCliD DURATION Lg Ng Ng Ng L U
D5713/88 "DTil57 0.17 6T67 0.17 0.1630 05:00:34 2 Hours 08/13/88 0.0901 0.08 -0.10 0.00 0.0115 12:43:26 2 Hours 08/13/88 0.0901 0.09 -0.09 0.01 0.0115 12:43:47 2 Hours 08/13/88 -0.1146 -0.12 -0.22 -0.12 -0.1151 20:50:24 2 Hours 08/14/88 0.0543 0.05 0.14 -0.04 -0.0368 04:38:16 2 Hours ,
08/14/88 0.1186 0.12 0.01 0.11 0.1183 22:13:07 2 Hours 08/15/88 0.0848 0.08 -0.07 0.03 0.0344 07:47:00 2 Hours G = identified gross leakage U = Unidentified leakage L = Licensee calculated N - NRC calculated Columns 2 and 3, 5 and 6 correlate + 0.2 gpm in accordance with NUREG 110 N is corrected by adding 0.1044 gpr to the NUREG 1107 N due to total purge flow through the No. 3 seal from RF
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