IR 05000289/1986009
| ML20212B754 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 07/23/1986 |
| From: | Blough A, Conte R, Dante Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20212B735 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.E.4.2, TASK-TM 50-289-86-09, 50-289-86-9, IEB-85-001, IEB-85-1, NUDOCS 8608070221 | |
| Download: ML20212B754 (26) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
Report No.
50-289/86_09 Docket No.
50-289 License No.
DPR-50 Priority --
Category C Licensee:
GPU Nuclear Corporation post Office Box 480 Middletown, Pennsylvania 17057 Facility At:
Three Mile Island Nuclear Station, Unit 1 Inspection At:
Middletown, Pennsylvania Inspection Conducted:
May 17, 1986 - June 27, 1986 Inspectors:
R. Conte, Senior Resident Inspector (TMI-1)
D. Johnson, Resident Inspector (TMI-1)
J. Rogers, Resident Inspector (TMI-1)
P. Wen, Reactor Engineer F. Young, Resident Inspector (TMI-1)
Reporting Inspector:
M 7~' D - K fon. D. JoMion, Resident Inspector (TMI-1)
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Reviewed By:
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7-23-JG h R. Coffte, Senior Resident Inspector (TMI-1)
Date Approved By:
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"7 23-dC A. 81dtigh, Chief Date Reactor Projects Section No. lA Division of Reactor Projects Inspection Summary:
Resident and region-based NRC staff conducted routine safety inspections (323 hours0.00374 days <br />0.0897 hours <br />5.340608e-4 weeks <br />1.229015e-4 months <br />) of power operations, focusing on plant and personnel performance.
Specifically, items reviewed in detail in the operation and maintenance areas were:
Intermediate Closed Cooling (ICC) System radioactivity; reactor trip channel actuation; and the reactor trip on June 2, 1986. Other items includ-ed: boric acid systems operability; 10 CFR 50.59 annual report; Static 0-Ring products evaluation; containment integrity modification (NUREG 0737, Item II.E.4.2); station IE battery testing; and licensee action on previous find-ings.
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Inspection Results:
The inspectors continued to observe good overall control over operational and maintenance activities by the licensee. The licensee's response to the June 2, 1986, reactor trip was adequate with evidence of proper procedure adherence. As a result of the inspector's review of that trip, a concern developed on the adequacy of procedures and training related to operator haste to energize non-safety electrical busses from safety busses in an attempt to prevent a plant trip.
No violations were identified. Several unresolved items were identified or reviewed concerning boric acid system surveillance, and primary-to-secondary leak rate procedure.
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DETAILS 1.
Introduction and Overview 1.1 NRC Staff Activities The overall purpose of this inspection was to assess licensee activities for the power operation mode as they related to reactor safety. Within each area, the inspectors documented the specific purpose of the area under review, scope of inspec-tion activities and findings, along with appropriate conclu-sions.
The inspector made this assessment by reviewing infor-mation 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 documents. A resident inspector participated in a Regulatory Effectiveness Review (RER) of the licensee's security program, focusing primarily on implementation. This review will be addressed in a separate report.
1.2 Licensee /.ctivities During this period the licensee operated the plant at full power, except for a period of twenty-four hours after the reactor tripped on a turbine trip. The licensee response to this trip is discussed in paragraph 3.2.
Routine operations, maintenance, and surveillance were conducted.
2.
Plant Operations 2.1 Scope of Review The NRC resident inspectors periodically inspected the facility to determine the licensee's compliance with the general operat-ing requirements of Section 6 of the Technical Specifications (TS) in the following areas:
review of selected plant parameters for abnormal trends;
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plant status from a maintenance / modification viewpoint,
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including plant housekeeping and fire protection measures; control of ongoing and special evolutions, including
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control room personnel awareness of these evolutions; control of documents, including logkeeping practices;
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implementation of radiological controls; and,
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implementation of the security plan, including access
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control, boundary integrity, and badging practices.
Because of additional resident office coverage at this facility, more detailed and frequent reviews of operating personnel performance were conducted to determine that:
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operators are attentive and responsive to plant parameters and conditions; plant evolutions and testing are planned and properly
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authorized;
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procedures are used and followed as required by plant policy; equipment status changes are appropriately documented and
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communicated to appropriate shift personnel;
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the operating conditions of plant equipment are effective-ly monitored and appropriate corrective action is initiat-ed when required;
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backup instrumentation, measurement, and readings are used
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as appropriate when normal instrumentation is found to be defective or out of tolerance;
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logkeeping is timely, accurate, and adequately reflects plant activities and status; operators follow good operating practices in conducting
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plant operations; and, operator actions are consistent with performance-oriented
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training.
The inspectors focused attention on the areas listed below.
General / Operations Control room operations during regular and backshift
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hours, including frequent observation of activities in progress, and periodic reviews of selected sections of the shift foreman's log and control room operator's log and other control room daily logs
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Followup items on activities that could affect plant
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safety or impact on plant operations Areas outside the control room
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Selected licensee planning meetings
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Fire barrier integrity
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Maintenance Work planning meetings
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Decay heat system loop A maintenance
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Ventilation system process monitor, RM-A6, repair activi-
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ties Radiological Controls Locked high radiation doors
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Radiation Work Permit posting
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Surveillance Boric acid mix tank, storage tanks, and associated
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equipment As a result of this review, the inspectors reviewed specific events in more detail as described in the sections that follow.
2.2 Findings 2.2.1 General
During this period, licensee management continued their presence and involvement in daily activities. While the plant remained at full power, except as discussed in paragraph 3.2, the licensee continued to work selected modifications. Overall, the licensee exhibited positive control and involvement to ensure that the work did not have an adverse effect on plant operations.
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2.2.2 Intermediate Closed Cooling System Radioactivity During the eight months of operation since restart, the licensee has experienced primary plant leakage into the Intermediate Closed Cooling System (ICC) via the letdown heat exchangers.
These heat exchangers are coil type heat exchangers with primary coolant in the tube coil side.
Leakage has been evidenced by increasing ICC surge tank level and increasing activity on the ICC system radiation monitor, RM-L9. Activity in the ICC system as high as 6.0E-3 uCi/ml (microcuries/ milliliter) has been observed by direct sampling (approximately 2.0E5 cpm on RM-L9 scale). The radiation monitor in the control room has been in the alert range for a significant portion of the reporting period.
For brief periods, the monitor reached the high alarm (4.0E5 cpm) range.
This leak has not presented an airborne or radiation problem in the auxiliary building based on licensee monitoring of the system.
Leakage has stabilized and decreased somewhat since the June 3, 1986, reactor startup.
During the first weeks of the report period, leakage into the ICC system had increased to approximately 8 gallons per day.
The licensee had tracked this leakage and evaluated the consequences of a much larger leak into the ICC system from the letdown heat exchangers. A leak rate which would essentially peg high the RM-L9 indicator would not result in measurably higher radiation levels in the auxiliary building.
This was deter-mined by extrapolation of present radiation readings to corresponding increases in the RM-L9 reading.
Present radiation levels at the ICC piping in the auxiliary building are only slightly above back-ground.
In the event of a larger leak, radiation levels would increase in the vicinity of ICC system piping in the auxiliary building but can be detected by virtue of RM-L9 either alarming in the control room or by observation of increased RM-L9 inoication above the alarm point. Also, the leak could be isolated remotely by closing the letdown heat exchanger isolation valves from the control room and, also, isolating the ICC piping at the containment boundar.
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The licensee-has ordered and has plans to replace both heat exchangers during the 6R outage. At present, one heat exchanger is isolated and one is in service. The licensee continues to monitor the ICC I
system activity and the NRC resident office will continue to routinely review this area.
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2.2.3 Rx Trip Channel Actuation
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During maintenance on RM-L6, Liquid Waste Discharge Process Monitor, on June 6, 1986, one-of-two a.c.
reactor trip breakers, CB-11, tripped when power to i
Reactor Protection System (RPS) Channel B was lost.
This was due to the tripping of the RPS-B feeder switch on the "B" vital bus.
Electricians were working on RM-L6 in the control room and, during wiring removal, an untaped lead came in contact with a terminal block lug on RM-L4, Nuclear Service Closed Cooling (NSCC) process monitor, located directly above RM-L6. The resulting voltage spike caused the RPS-B switch to trip.
RM-L4 power is supplied from vital bus "B".
No equipment response occurred although several annunciators alarmed.
One Engineering Safeguards Actuation System (ESAS) and RPS channel tripped but no ESAS actuation occurred.
The licensee reclosed the breaker and reset the protection system signals and ESAS signals.
The inspector observed work in progress on removal of RM-L6 in the control room. The clearances between RM-L6 and RM-L4 wiring connections are very small and care must be taken to prevent this type of problem.
The electricians normally tape the disconnected metal lugs when these lugs are removed from instruments, and it was during this process that an uninsulated lug made contact with the RM-L4 terminal block.
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The licensee has not had a significant problem with this type of occurrence. The personnel involved were aware of the consequences of this type of work with energized switch boards and energized adjacent instrumentation. The inspector concluded that the I&C personnel were using appropriate work methods, but that they needed to exercise greater care when doing this type of work.
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The inspector had no other safety concerns. Although not specifically required by administrative controls, the licensee did not take the initiative to document this event in a plant incident report (PIR).
The inspector reviewed the administrative procedure for PIR's and determined that the procedure did not specifically require a PIR for this event. The licensee has the option to lower the threshold for PIR preparation but chose not to do so in this case.
The NRC resident office will continue to routinely review the use of PIR's versus actual plant events that periodically occur.
2.3 Conclusion The licensee exhibited reasonably good control over the various operational, maintenance, surveillance, and modification work activities. They continued to implement an ambitious preven-tive maintenance program.
In general, care was exercised for work activities, especially those involving modifications, to not adversely affect plant operations.
Equipment malfunctions occurred and personnel errors were made.
However, none significantly impacted safe operations. Appro-priate reporting occurred and adequate corrective actions were either taken or planned.
3.
Event Followup 3.1 Introduction During the inspection period, the NRC staff reviewed, in detail, the reactor trip on June 2, 1986, along with one problem that occurred at another nuclear plant.
In general, the following aspects were considered:
details regarding and cause of the event;
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functioning of safety systems;
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licensee action with respect to procedures;
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radiological consequences;
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license proposed corrective action;
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verification of plant performance; and,
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proper notification.
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i 3.2 Reactor Trip from Turbine Trip 3.2.1 Sequence of Events
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On June 2, 1986, at 2:11 p.m., the reactor tripped from 100 percent power. The cause of the trip was the anticipatory trip from the turbine trip.
The turbine tripped when both electro-hydraulic control (EHC) oil pumps were de energized during turbine plant electric 480 VAC breaker repair evolutions that were being accomplished at the time.
Events preceding the trip on June 1, 1986, had necessitated the replacement of the feeder breaker to
the 1C turbine plant load center. The breaker 1C-02 had tripped on Sunday afternoon, June 1, 1986,
resulting in the loss of several secondary plant
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loads; among them were two condenser vacuum pumps and one EHC pump.
During this breaker trip, standby pumps had picked up some loads lost on the IC bus.
Condenser vacuum had decreased to 24 in. Hg. (close
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to a turbine trip setpoint) before a second vacuum
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pump could be restarted.
The licensee reclosed the 10-02 breaker after determining that there was no physical damage or apparent reason for tripping.
They then shifted some loads off the 1C load center to other sources.
A decision was made to replace the IC-02 breaker on June 2, 1986, and the electrical lineup would be to supply motor control centers (MCCs) (normally supplied by the IC 480 VAC bus) using the cross-connect breakers from other turbine plant (TP)
MCCs.
Specifically, the IJ 480 VAC bus normally supplying the ID and IB turbine plant (TP) MCCs would supply the 1A and IC (TP) MCCs via the aforementioned MCC cross-connect breakers. The result was that both EHC pumps would be supplied from the IJ 480 VAC bus.
After unloading the IC 480 VAC bus, the IJ bus to ID MCC feeder breaker tripped, causing the loss of both EHC pumps (off the IC and 10 MCCs) and a subsequent
plant trip resulted.
The plant was restarted on June 3, 1986, and selected evolutions were observed by the inspector.
During the brief shutdown period, the licensee made minor repairs. Among them was a leak on an EHC control system reservoir. This leak was not related to the trip.
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l 3.2.2 Scope of NRC Review A resident inspector was in the control room at the time of the event. The inspector reviewed licensee
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action during the event and subsequent startup, reviewed appropriate documentation associated with this event and also monitored the licensee's event j
critique. Specific procedures reviewed were:
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Operating Procedure (0P) 1107-1, " Normal Electrical System," plant annunciator response procedures for loss of 480 VAC breakers; Post-Trip Review Adminis-trative Procedure (AP) 1063; and associated computer printouts and contral room strip chart records.
During subsequent restart and power escalation operations, the inspectors were on site to witness control room and plant operations. The inspectors also conducted interviews with various plant engi-neering, maintenance, and operations personnel.
3.2.3 Licensee Findings The licensee conducted a post-trip review in accordance with AP 1063. The licensee determined the cause of the trip to be the loss of both EHC pumps, resulting in a turbine trip.
Plants response was normal during the event although plant parameter T-Cold did not decrease to the expected temperature (545 F) in the required 10-minute interval. OTSG pressure, pressurizer level, and T-Hot all attained their expected values in the expected time frame. The licensee is to evaluate the parameters and required response times for any procedure changes needed.
The licensee considers this response acceptable for this event. The licensee reported that approximately 25 micro-curies of noble gas were released from the lifting of the main steam relief valves during the event.
The licensee determined that the breaker that tripped (1J to 10 MCC feeder) had the "B" phase overcurrent trip set at 420 amps vice 600 amps.
The licensee replaced the IC-02 breaker with a breaker that uses a solid state over-current trip mechanism, which is substantially more reliable than the pneumatic / electric devices installed on most 480 VAC Plant breakers of this type.
The licensee plans to convert more breakers to this type of overcurrent trip device, especially in safety-related applications, in future repair.
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The post trip review also identified some confusion on the part of the licensee's personnel on proper electrical line-up to repair IC-02.
For example, engineering personnel were not aware of the particular electrical lineup that would be used to ensure all electric plant loads would re-main powered during the repair. Control room or maintenance personnel had not properly evaluated what load this breaker would have during the abnormal electrical lineup. This would not have prevented the breaker from tripping but may.
have resulted in more concern in the control room for the '
evolution taking place.
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The licensee also determined that OP 1107-1 was deficient concerning instructions for the particular electrical lineup that was to be used. A change to this procedure is being prepared to more clearly describe this type of lineup.
3.2.4 NRC Findings The inspectors determined that licensee immediate and followup corrective actions to this trip were appro-priate.
The inspectors reviewed plant data to confirm the licensee's post-trip evaluation. The root cause of the trip was reasonably determined to be equipment malfunction during the maintenance activities.
The inspectors also determined that a part of the licensee action in response to the loss of both EHC oil pumps was an attempt to supply power from the 1N 480 VAC bus to the de-energized turbine plant (1C 480 VAC) bus in order to restore power to the EHC oil pumps.
This action also occurred during the loss of the IC bus on the previous day. The 1N 480 VAC bus is supplied by the 10 4160 VAC ES bus, a safety-related electrical bus.
Licensee operating procedures and emergency procedures for loss of offsite power allow the use of the 1N bus to be cross-tied to either the IC, IJ, IG, or il turbine plant buses (non-safety). The intent is to supply power to selected turbine plant loads; such as, main turbine and main feed pump jacking gear to prevent damage to this equipment.
This cross-tie situation cannot be made if an ES sigral is present on the ID 4160 VAC ES bus.
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The inspector questioned the licensee on the prudence of attempting to connect a vital 4160 load center to a possibly defective bus apparently to prevent a reactor trip. While observing the event response, it was evident to the inspector that control room personnel were not fully aware of the nature of the fault on the IC 480 VAC MCC at the time of the event.
The inspector concluded that more guidance and training was needed for control room operators on the prudent use of the IN bus involving the loss of non-safety-related busses.
Licensee management agreed to review this area. This item remains unresolved pending licensee review of any necessary procedural or training changes related to the use of the 1N bus (289/86-09-01).
The inspector also concluded that the weak mainte-nance procedure, along with a lack of technical support coordination, contributed to this event. The inspectors will also follow licensee upgrading of the 480 VAC breaker overcurrent trip devices as these changes are made (289/86-09-02).
Plant respense was normal. The licensee returned the plant to operation after appropriate repairs and evaluations were made.
The related licensee event report will be reviewed upon receipt. The inspector had no other concerns in this area.
3.3 Static 0-Ring Inc. Instruments 3.3.1 Event A problem with Static 0-Ring Inc. (SOI) instruments was noted at the LaSalle Nuclear Plant. The problem involved the failure of three of four SOI pressure switches activa-ting on a low reactor water level condition.
Further, there was a concern that the switches were exercised before as-found data was recorded during periodic surveillance.
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Static 0-Ring products (pressure switches) are used by the licensee et TMI-1 in one safety-related application. The pressure switches used to isolate main feedwater on a steam line rupture are Static 0-Ring Model No. 9TA-845-NX-CIA-JJTTXG. They are installed (two each) on the four main steam lines exiting the once-through steam generators (OTSGs).
At 600 psig, they are designed to activate to shut the feed regulating valves and start up feed regulat-ing valves and the associated block valves.
The licensee has recently installed these detectors as part of an environmental qualification program upgrade for instrumentation inside the reactor building.
3.3.2 NRC Review Procedures used to calibrate various instrument pressure switches, D/P detectors, and pressure gauges were reviewed to verify that "as-found" data was recorded when instruments were calibrated. This verification is accomplished for all procedures reviewed (i.e., corrective maintenance procedures 1430-Y-4,6,13,17, 25). The data for the latest calibration of the eight pressure switches was reviewed by the inspector and revealed no unusual problems. As-found data was within 1 percent of setpoint for the detectors.
3.3.3 Conclusion Static 0-Ring products are used at TMI-1, but there appears to be no problems associated with their use in safety related applications. A review of several corrective maintenance procedures revealed that
"as-found" data is recorded in the various proce-dures.
This concern appears to be adequately ad-dressed at TMI-1. This inspector had no additional questions.
4.
Boric Acid Makeup Operability 4.1 Scope The scope of this review included the instrumentation, valve alignment, chemical support, and electrical distribution for the followir.g components specified in Technical Specification (TS) 3.1.
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Borated Water Storage Tank (BWST)
Boric Acid Mix Tank (BAMT) and the two associated boric
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acid (BA) pumps Two Reclaimed Boric Acid Storage Tanks (RBAT or RBAST) and
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the two associated reclaimed boric acid pumps The inspector assessed the operability of the boric acid makeup system based on a review of licensee maintenance (preventive and corrective) and surveillance activities to verify that:
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the requirement of TS 3.3.1.1 and 3.2.2 are met; applicable procedures required by TS 4.1.1 (Table 4.1-1)
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are being properly implemented;
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applicable procedures have the proper format and technical content in accordance with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWP, and applicable sections of ANSI N18.7-1976;
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surveillances and preventive maintenance (PM) were con-ducted -at the proper frequency; and, machinery history records and related surveillance preven-
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tive maintenance records were retrievable.
4.2 Review In addition to discussions with cognizant licensee personnel (mainterance, operations, and engineering), the inspector reviewed selected portions of the following licensee documents and records:
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Surveillance Procedure (SP) 1301-2, " Boric Acid Mix Tank or Reclaimed Boric Acid Tank," Revision 11, dated February 15, 1986, including data obtained April 24, 1986 and June 16, 1986;
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SP 1300-3S, " Boric Acid Injection System Functional Test,"
Revision 2, dated May 29, 1985, completed May 31, 1985;
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SP 1301-4.4, " Borated Water Storage Tank," Revision 9, dated May 29, 1985, completed May 12, 1986, and June 16, 1986; SP 1301-5.1, "BAMT Temp Channel, RBAST Temp Channel,"
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Revision 5, dated October 24, 1985, completed March 3, 1986, and June 3, 1986;
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SP 1302-5.19, " Borated Water Storage Tank Level Indica-
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tor," Revision 8, dated July 18, 1985, completed January 29, 1986;
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SP 1302-5.20, " Boric Acid Mix Tank Level and Temp Chan-nel," Revision 7, dated February 2,1985, completed April 5, 1986; SP 1302-5.21, " Reclaimed Boric Acid Storage Tank Level and
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Temperature Channels Calibration," Revision 6, dated February 14, 1986, completed April 5, 1986;
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Operating Procedure (0P) 1104-4, " Decay Heat Removal System," Revision 57, dated March 20, 1986, completed April 15, 1986; OP 1104-29E, " Bleed and Feed Processes," Revision 19,
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dated March 20, 1986, completed April 4, 1986; and,
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Inservice Testing (IST) program as documented in the letter from H. D. Hukill, TMI-1, to J. F. Stolz, NRR, dated July 10, 1984, and March 3, 1986.
By visual inspection (system walkdown) or remote valve position indication, the inspector verified the required valve alignment for the BWST, BAMT, and RBATs in accordance with technical specifications. The following diagrams were referred to during the system walkdown: C-302-640, " Decay Heat Removal;"
C-301-670, " Chemical Addition;" C-302-692, " Liquid Waste Disposal;" C-302-660, " Makeup and Purification;" and, C-302-712, " Reactor Building Spray."
4.3 NRC Findings 4.3.1 The licensee has asked for relief from quarterly pump test requirements specified in ASME Code,Section XI, for the boric acid (BA) pumps (per IST program specified in licensee letter, dated March 3, 1986). The BA pumps (CA-P1A/B) do not have a recirculating flow path. A flow test of these pumps would inject concentrated boric acid solution directly into the makeup tank leading to the generation of a large quantity of liquid radwaste and upset the reactivity balance in the reactor during power operation.
Therefore, the licensee has requested a refueling test interval for the BA pumps to prevent unnecessary liquid waste generation.
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The inspector confirmed that there is no recirculat-ing capability for the BA pumps and, also, there is no flow indication or pressure indication for the BA and reclaimed boric acid pump suction and discharge lines. Heat tracing is provided for all pump suction and discharge lines to help prevent boron crystalli-zation inside these lines.
The normal boration flow path for normal operations is to pump concentrated boric acid solution into the makeup tank using either the 10 gpm BA pumps or the 30 gpm reclaimed boric acid pumps.
Therefore, during normal operations, these pumps will be run periodi-cally (boration is accomplished manually at shut-down), but there may be long periods of time (months)
during which these pumps will be idle.
Even with heat tracing, there is a possibility that idle boric acid solution filled lines can become clogged from boric acid crystallization, thereby hindering the capability of these pumps to discharge into the makeup tank. Since the reclaimed boric acid pumps do have a recirculation line, they can be started and flow verification can be made (quarterly by the IST program). Without periodic flow testing of the boric acid pumps, it is questionable if the licensee can be sure that pump damage or line blockage has not occurred due to the boron crystallization effecting the operability of these pumps.
In the letter from J. F. Stolz, NRR, to H. D. Hukill, TMI-1, dated December 11, 1984, NRR denied relief from the ASME Code IST requirements for the second 120-month IST interval (September 1984 to September 1994) as requested in the licensee letter dated July 10, 1984, providing the updated IST program in accordance with 10 CFR 50.55a(g)(5)(iv).
The licensee was given twelve months after restart to implement required ASME testing or obtain additional relief. Therefore, the licensee has until October 3, 1986, to adhere to the IST program, dated July 10, 1984, as approved by NRR.
In the IST program transmitted by letter, dated March 3, 1986, the licensee again requested that the boric acid pumps be tested each refueling interval versus quarterly.
NRR is in the process of reviewing the latest relief request. This is unresolved pending NRR disposition of the subject relief request or October 3, 1986, g
which ever comes first (289/86-09-03).
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4.3.2 Section 8.2 of SP 1302-5.20 involves the calibration of the BAMT level transmitter (CA-13-LT) as required by TS 4.1-1.
Calibration of the level transmitter requires its removal to the I&C shop.
Since there is no transmitter isolation valve, the BAMT must be drained to alternate tanks and/or its contents processed as radwaste in order to allow removal of CA-13-LT.
Instrumant CA-13-LT was last calibrated on June 16, 1984, and, according to the licensee's program, was due for calibration on June 16, 1986.
Currently, the BAMT is the designated TS alternate source of boric acid in addition to the BWST (TS 3.2.2).
Accordingly, the licensee made the decision to not calibrate CA-13-LT. Because of the inability to calibrate CA-13-LT, Section 8.2, of SP 1302-5.20 could not be completed. The licensee documented on a deficiency report (deficiency No. 2 for SP 1302-5.20, dated April 5, 1986) that CA-13-LT could not be calibrated and that the transmitter would be out of service as of June 16, 1986, and subsequent BAMT ievel checks would have to be taken manually. On June 16, 1986, the licensee commenced using a 0 to 15 psig pressure gauge (PI-743) or, the outlet line of the BAMT. Once per shift, operators convert gauge pressure to inches of boric acid for level indication as a comparison with CA-13-LT. The manual calculation is corrected for specific gravity.
4.3.3 During the review of SP 1302-5.20, " Boric Acid Mix Tank Level and Temp Channel," completed on April 4, 1986, the inspector noted an apparent inconsistency in the technical specification definition of refuel-ing intervals.
TS Table 4.1-1, "R" is defined as each refueling period.
Each refueling period is not defined in Technical Specifications, but the licensee states that they define the refueling period to be the REFUELING INTERVAL defined in the Definitions Section of Technical Specifications (Section 1). On page 1-2 of the Technical Specifications, REFUELING INTERVAL is defined as the time between normal refueling not to exceed twenty-four months without prior NRC approval. However, page 1-8, TS Table 1.2, defines
"R" as the refueling interval of once per eighteen months with a maximum allowable extension of 25 percent.
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The refueling period is discussed in numerous sec-tions of the Technical Specification. The apparent conflict between an 18-month versus 24-month refuel-ing interval and the lack of a clear definition of refueling period has led to confusion in interpreting Technical Specifications.
Standard Technical Speci-fications define the refueling period as eighteen months with a maximum extension of 25 percent. The licensee agreed to submit a TS change to resolve this issue by January 1, 1987. This is unresolved pending
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completion of licensee action as stated above and subsequent NRC review (289/86-09-04).
4.3.3 During review of the licensee's proposed periodic inservice inspection program, the inspector noted that valve MU-V10 was not included on the valve list to provide assurance of the operability of this valve. MU-V10 is the isolation valve for the alter-nate discharge flow path from the BAMT and RBATs to the makeup tank for the normal boration of the reactor. The normal flow path from the BAMT and RBATs is through valve MU-V51 to the makeup tank.
Two flow paths are provided so that a single failure will not prevent the boration of the reactor coolant system (RCS) to a one percent sub-critical margin in the cold condition. MU-V51 is listed in the IST program for quarterly full stroke and failsafe testing.
If valve MU-V51 fails or that discharge line is not capable of usage (line break, clogged, etc.), the licensee would be required to depend on MU-V10, an untested valve, to allow normal boration of the RCS.
Two valves, WDL-V61 and WDL-V361, upstream of MU-V10 are included in the IST testing program, since they are both required to function properly for alternate normal boration. When the above information was brought to the attention of licensee mechanical engineering personnel, they agreed to evaluate the inclusion of MU-V10 in the IST program.
This is unresolved pending completion of licensee action as stated above and subsequent NRC review (289/86-09-05).
4.4 Conclusions During the walkdown of the BWST, BAMT, and RBATs, all valves were properly positioned and the appropriate electrical distri-bution systems aligned as per the various documents, proce-dures, and diagrams reviewed. A review of chemical sampling
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documentation (computer data files) indicated that the chemical analysis of the boron concentration in the BWST, BAMT, and RBATs is obtained and documented as per technical specifica-tions, surveillances, and operating procedure _
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A number of unresolved items were identified which warrant additional review by licensee and NRC.
5.
TMI Action Plan Item II.E.4.2 Verification 5.1 Introduction TMI Task Action Plan (TAP) Item II.3.4.2, " Containment Isola-tion Dependability," was initiated for licensees to review containment isolation systems and make required modifications for diverse sig'nals to isolate the containment. At TMI-1, this upgrade was accomplished by three separate modifications termed
" restart modifications" (RM). The following tasks added new systems or modified existing systems with additional contain-ment isolation or diverse containment isolation for existing valves.
RM-5B - Reactor Building Isolation on High Radiation
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RM-5C - Reactor Building Isolation on Rx Trip /High Reactor
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Building Pressure /High Pressure Injection (HPI)
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RM-50 - Reactor Building Isolation on Nuclear Services /
Intermediate Closed Cooling (NSCC/ICC) pipe break 5.2 Scope of Review The inspector reviewed previous NRC Region I inspection re-ports, listed below, which described the staff's earlier partial verification of these items. The licensee's implemen-tation of these equipment installation / modification items had been inspected over a period of several years.
Restart Previous Modification Description Inspections RM-5B RB isolation on high 82-01, 82-07 radiation 82-19, 81-26 84-08 RM-SC RB isolation on Rx Trip /
80-05, 80-31, HPI/RB pressure 81-08, 82-07 82-24, 82-26 RM-5D RB Isolation on NSCC/ICC 82-26, 83-02 pipe break 83-12, 83-14 83-32, 84-01 The purpose of this review was to determi.1e whether previous NRC inspections had sufficiently verified the implementation of these items.
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5.3 Findings Based on the inspector's review of previcus inspections, the inspector determined that the licensee's implementation of the above modifications had been verified to be acceptable in all respects with one exception.
Modification RM-58 installed several new radiation monitors.
These monitors would generate an interlock signa' to close valves to isolate the piping with increased external radiation levels. The technical basis for the monitor interlock setpoints for RM-G16 to 21 and RM-L1 was not available to the inspectors at the time of review and an unresolved item (No.
289/84-08-02) was opened for licensee review of this area.
Additional verification / calculation is still required to correlate the setpoints (micro Ci/cc) listed in System Design Description (SDD)-642A with the actual setpoints (mr/Hr) for the isolation function. This item remains unresolved at this time.
5.4 Conclusion TAP Item II.E.4.2, " Containment Isolation Dependability," is closed and the NRC TAP tracking system will be updated to reflect this fact.
The open item on interlock set point bases is being tracked as unresolved item 289/84-08-02.
6.
Startup Report for Restart 6.1 Scope of Review The startup report submitted by the licensee pursuant to Technical Specifications 6.9.1 was reviewed by the inspector to verify that modifications to the plant may have significantly altered the nuclear, thermal, or hydraulic performance of the plant.
For each modification identified, the licensee was required to describe the test used to verify plant performance, including a description of the measured values of the operating conditions or characteristics ob-tained during the test program and a comparison of these values with design predictions and specifications. Any corrective actions that were required to obtain satisfactory operation were to be described in the report.
6.2 Findings The startup testing program was divided into two parts:
Hot Functional Testing (HFT) and Power Escalation Testing (PET).
Two HFT tests, which had unsatisfactory test results -- High Pressure Injection System Functional Test and Power-Operated
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Relief Valve Flow Indication Functional Test -- were reperformed satisfactorily prior to Cycle 5 initial criticali-ty.
All test results and conclusions in the PET were either within acceptable limits or were evaluated and determined to be an acceptable variation from the limits relative to plant safety consideration.
The report documents the chronological events during the entire restart startup test period. Test objectives, test methods, test results, and conclusions were included for each test. The report content was consistent with the NRC inspection reports issued during that period, 50-289/85-22 through 85-30, which were performed through direct inspection observaticas. The inspector concluded that reports submitted fulfilled the requirements of Technical specifications 6.9.1.
7.
Review of Licensee's 10 CFR 50.59 Report for 1985 7.1 Scope of Review The inspector reviewed the licensee's 10 CFR 50.59 report for 1985 submitted April 17, 1985, to Regional Administrator, Region I.
This review included the following considerations.
The report: identified and briefly described the modifica-tion / changes, and briefly stated the licensee's evaluation of the effect the change or modification had on the facility. The inspector on a sampling basis reviewed additional documentation associated with selected modifications. This review was performed to verify that the modification was performed in accordance with applicable station procedures and the modifica-tion was tested and test data evaluated with an established acceptance criteria. The inspector reviewed the changes or modifications to ensure safety evaluations accurately described the modifications or changes and did not generate an unreviewed safety question.
Personnel training associated with plant changes was reviewed to ensure training was performed, signifi-cant information was disseminated to the correct individual who may need to understand the change.
The inspector reviewed selected station procedures that may have been effected to ensure applicable changes to them were made.
7.2 NRC Findings Based on this review, the inspector concluded that the facility changes did not generate any unreviewed safety questions.
Various modifications were subject to inspection prior to restart and these reviews were documented in various 1985 inspection reports.
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In general, the inspector concluded that the report met the submittal requirements of 10 CFR 50.59.
8.
Licensee Action on Previous Inspection Findings 8.1 [ Closed)InspectorFollowItem(289/85-25-06):
Proper Documentation of Exceptions and Deficiencies noted during Surveillance Tetting This item was opened to follow the licensee's action resulting from the improperly administered Exception and Deficiency (E&D)
sheets, which are used to note problems during the performance of station surveillances.
The licensee issued Revision 5 to Administrative Procedure (AP) 1001J on May 27, 1986, to clarify and change the instructions for review of surveillance test problems. A new E&D fcrm requires the shift supervisor to review deficiencies for technical specification operability, action required, and reportability.
It also requires the shift supervisor to review exceptions to verify that the condition reported is actually only a procedure exception as defined by AP 1001J. Revision 5 to AP 1001J was reviewed by the inspector and it appears that the new changes will aid in assuring that surveillance test problems are properly considered for disposi-tion by the operations staff.
The inspector reviewed several E&D sheets that were being used after the revision to AP 1001J was issued. All sheets reviewed were properly retained, completed, and contained the appropri-ate level of review.
It should be noted that the E&D sheet is only a vehicle to assure a review of surveillance test problems by the operations staff.
Decisions regarding operability of equipment and reportability must be made on a case-by-case basis by the operations staff, using their judgement along with other plant procedures and guidance.
The inspector concluded that appropriate corrective action has been initiated by the licensee to adequately resolve
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problems arisin'g from the initial finding. Accordingly, this
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item is closed. The inspectors will continue to randomly review licensee action on individual E&D sheets per AP 1001J in future inspections.
8.2 (Closed) Unresolved Item (289-/85-30-01):
Evaluation of the Effects of Introducing Chemical Sealants into Steam Generators Uue to a body-to-bonnet leak on FW-V1093, an unisolable steam generator level indicating transmitter root valve on the 1A OTSG, seven sticks of Furmanite were injected into the valve at various times during 1985 and 1986. The sensing line eventual-ly was plugged by the "furmanite" compound and it had to be
" blown into" the steam generator. The licensee had not provid-ed an evaluation of the consequences of the "furmanite" com-I
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pounds entering the steam generator prior to the repair pro-cess. This problem was also the subject of IE Information Notice 85-90.
Plant engineering evaluated the potential problems of various "furmanite" compounds entering the steam generator based on chemical analysis data supplied by Furmanite Corporation and an Electric Power Research Institute (EPRI)
study (Report EPRI NP-3111, May 1983). The inspector reviewed the EPRI report and the licensee's evaluation of "furmanite" contamination in the OTSG secondary side.
It was anticipated that some of the "furmanite" compounds would disassociate in the OTSG environment and that some compounds could enter the OTSG and lodge in the tube support plates. The chemical contaminants evaluated were well within defined limits for use in nuclear power plants.
It is unlikely that all of the "furmanite" compounds would have entered the steam genera-tor.
The EPRI report also concluded that "furmanite" compounds were not detrimental to the metallurgy or chemistry of reactor components. The inspector concluded that the licensee's evaluation was satisfactory based on the EPRI report and the fact that very small amounts of the "furmanite" had entered the steam generator. Since that startup, the reactor power has not been limited by steam generator high water level. The inspec-tor had no other comments.
8.3 (Closed) Inspector Follow Item (IE Bulletin 85-01):
Steam Binding of Auxiliary Feedwater Pumps.
The inspector reviewed the licensee's followup action regarding IE Bulletin 85-01.
IEB 85-01 concerned the possible hot water leakage into the emergency feedwater system (EFW) through leaking check valves causing possible steam binding and subsequent disabling of the EFW pumps. The inspector reviewed the following documents:
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IE Bulletin 85-01 Inspection Report 50-289/85-20, Item 3.1, " Steam Binding
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in Emergency Feedwater System" Licensee's response to IE Bulletin 85-01, dated February i
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27, 1986
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OP 1106-6, Revision 46, dated June 12, 1986, " Emergency Feedwater" IEB 85-01 required the licensee take the following actions.
Develop procedures for monitoring fluid conditions with
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the EFW system on a regular basis during times when the system is required to be operable..
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The inspector confirmed that the secondary auxiliary operator's log sheet require monitoring the pipe temperature upstream of each EFW pump discharge check valve on each shift. According to the licensee, there has been no indication of a temperature rise above ambient over the last several months.
Develop procedures for recognizing steam binding and for
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restoring the EFW system to operable status should steam binding occur.
OP 1106-6, Revision 46, (EFW Operating Procedure), " Limitations and Precautions," Step 2.1.10, addresses the restoration of the EFW if steam binding occurs.
The procedure requires the securing of the affected pump and draining condensate storage tank water through the pump to a pump discharge vent valve if pipe temperature is in excess of 230 F.
TMI-l's EFW system uses a normally closed control valve (EF-V30A/B).
In addition, the line between the two OTSGs and each of the three EFW pumps are provided with two check valves (EF-V11A/B, EF/V12A/B, and EF-V13) in series. Triple isolation valves limit the likelihood of a steam binding problem.
With respect to the above bulletin, the inspector verified that licensee management forwarded copies of the bulletin response to appropriate onsite management representatives, that informa-tion and corrective action discussed in the reply was accurate and implemented as described, and that the reply was submitted within the time period described in the bulletin.
Licensee followup to the bulletin was acceptable.
8.4 (Open) Unresolved Item (289/85-19-01): The primary to secon dary leak rate procedure after power escalation testing.
The inspector reviewed that status of the licensee review of procedures associated with action to implement licensee condi-tion 2.C.8.2.
This condition requires that when steam genera-tor primary to secondary leak rate exceeds 6 gph above base-line, the reactor is to be shut down. The inspector determined that the licensee had not changed the criteria for action when measured leakage is between 6 gph to 12 gph above baseline.
Licensee procedures allow up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for stabilization and validation of the calculation. This time interval was accept-able to the NRC staff just prior to restart because of uncer-tainty in the stability of the calculation.
It appeared to the inspector that the PET established that the calculation was quite stable despite power maneuvering. Therefore, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> now seems unnecessarily long and there is no need for the 12 gph action limi.
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The licensee stated that the justification of why 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> was required for analysis would be forwarded in a letter to the NRC by September 1, 1986.
This item remains unresolved until NRC review of the licensee's submittal.
8.5 (0 pen) Unresolved Item (289/86-06-05): Station Battery Testing During 1A battery replacement testing during the last outage,
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the inspector noted a difference in the tests conducted for the 1A and 18 station vital batteries. This item was discussed with NRR representatives to determine if licensee testing of the IB battery and future testing of both batteries was accept-able or if additional test requirements are needed to assure battery operability over long periods of time. NRR representatives indicated that battery load duty cycle testing as was done on the 1A battery should be performed at intervals specified in IEEE Standards, specifically IEEE 450 and Regulatory Guide 1.129. This load duty cycle testing verifies the batteries capability to perform under design basis accident loading conditions.
In accordance with TS, the licensee presently conducts an 8-hour capacity test which discharges the battery at a constant rate on a refueling outage basis.
The inspectors discussed this with licensee engineering personnel and a licensee representative agreed to evaluate their test program for station IE batteries to determine if additional testing was necessary.
The additional testing discussed above is essentially the type that is required in standard technical specifications.
This item remains open pending additional licensee review.
The licensee committed to completing their review of additional battery testing by January 1, 1987. The new battery bank "A" has had a load duty cycle test. The
"B" battery bank is scheduled for replacement in the next refueling outage (November 1986 - April 1987), and it is expected to have an initial load duty cycle test after installation. Therefore, only the subsequent periodic testing is at issue and the January 1, 1987, commitment date is acceptable.
9.
Exit Interview The inspectors discussed the inspection scope and findings with the licensee management at a final exit interview conducted June 27, 1986.
Senior licensee personnel attending the final exit meeting included the following:
J. Colitz, Plant Engineering Director, TMI-1 l
H. Hukill, Director, TMI-1 M. Nelson, Manager, Nuclear Safety, TMI-1 C. Smyth, TMI-1 Licensing Manager A representative of the Commonwealth of Pennsylvania, Ajit Bhattacharyya, also attended the meeting.
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The inspection results, as discussed at the meeting, are summarized in the cover page of the inspection report.
Licensee representatives indicated that none of the subjects discussed contained proprietary or safeguards information.
Unresolved Items are matters about which information is required in order to ascertain whether the, are acceptable items, violations, or deviations. Unresolved item (s) discussed during the exit meeting are documented in paragraphs 3.2 and 4.3.
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