IR 05000341/1999009

Insp Rept 50-341/99-09 on 990516-0618.No Violations Noted. Major Areas Inspected:Operations,Engineering,Maint & Plant Operations

ML20209F673
Person / Time
Site:	Fermi
Issue date:	07/12/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20209F663	List: IR 05000341/1999009 ML20209F657
References
50-341-99-09, 50-341-99-9, NUDOCS 9907160100
Download: ML20209F673 (15)

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U.S. NUCLEAR REGULATORY COMMISSION i

REGION lll Docket No:

50-341 License No:

NPF-43 Report No:

50-341/99009(DRP)

Licensee:

Detroit Edison Company Facility:

Enrico Fermi, Unit 2 Location:

6400 N, Dixie Highway Newport, MI 48166 Dates:

May 16 through June 18,1999 Inspectors:

S. Campbell, Senior Resident inspector J. Larizza, Resident inspector K. Zellers, Resident !nspector, Davis-Besse S. Dupont, Project Engineer, Reactor Projects Branch 4

Approved by:

A. Vegel, Chief Reactor Projects Branch 6 Division of Reactor Projects i

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l 9907160100 990712

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PDR ADOCK 05000341 G

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EXECUTIVE SUMMARY L - <

Enrico Fermi, Unit 2 NRC Inspection Report 50-341/99009(DRP)

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This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 5-week period of resident inspection.

Operations Operators took prompt and appropriate action to scram the plant when the reactor

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entered the scram region of the power to flow map following the unexpected trip of a reactor recirculation pump. Plant equipment responded as expected. Activities to restart the plant were well coordinated. The licensee's investigation of the cause for the recirculation pump trip was timely and thorough (Section 01.1).

Operators conductri the plant restart in a controlled and deliberate manner following

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1 the May 18,1999, plam Mp. Shift tumovers and pre-evolution briefs for the power escalation were thorough and were conducted in accordance with' operations department policies (Section 01.2).-

- Operators responded effectively to several fouled heat exchangers cooled by the GSW

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system. Corrective maintenance activities were well planned and executed. There was good coordination among personnel from the engineering, operations, maintenance, and radiation protection organizations (Section 0.1.3 ).

The inspectors determined that contributing to the uncertainty regarding the applicability

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of TS 3.8.1.1.c to standby liquid control system equipment, was the lack of procedural

' guidance regarding what equipment was required per this TS. Also, control room operators did not communicate effectively with management or engineering personnel in determining whether TS 3.8.1.1.c was applicable to the standby liquid control systems,

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prior to removing Emergency Diesel Generator 11 from service for maintenance. As a

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result, once this configuration was questioned by the NRC, prompt actions were initiated l

which included briefing for a controlled plant shutdown. These actions, though appropriate and timely, could have been avoided if the applicability of TS 3.8.1.1.c was thoroughly evaluated prior to the plant being placed in a questionable configuration.

Weaknesses were also noted regarding documentstio.: and communication of equipment status. Specifically, control room operators did not document or communicate changes in the functionality of the standby liquid control system when l

power was removed to support trouble shooting activities. (Section O8.1)

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R Maintenance

. Tne pre-job brief and the coordination of troubleshooting activities for repairing a failed

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square root converter for the feedwater master controller were effective. The work package was properly prepared in accordance with the work control procedure

'(Section M1,1).

Instrumentation and Controls personnel demonstrated a good questioning attitude and

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effectively resolved a calibration problem with a jet pump flow instrumentation string.

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Engineering personnel provided effective support following the plant scram due to the

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unexpected trip of a reactor recirculation pump and in resolving the plugged general service water coolers. Engineering personnel effectively provided support in operability determinations and during scheduled maintenance outages (Section E3.1).

Plant Suoocrt The licensee was effective in maintaining radiation protection survey equipment

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calibrated and implementing effective radiation protection practices (Section R1.1).

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Report Details Summary of Plant Status Unit 2 began this inspection period at 97 percent power. On May 18,1999, operators manually tripped the plant when the unit entered the scram region of the power to flow map upon the unexpected trip of Reactor Recirculation Pump A. The licensee conducted an investigation into l

the cause of the pump trip and completed several maintenance activities. By May 23,1999, operators retumed the plant to 97 percent power.

On June 13,1999, operators lowered reactor power to 78 percent to clean the Northeast Main Turbine Hydrogen Cooler that were fouled with zebra mussels. Operators returned plant power to 97 percent the same day.

l. Operations

Conduct of Operations 01.1 - Operator Resoonse to the Unexpected Trio of Reactor Recirculation Pumo A a.

Inspection Scoce (71707)

The inspectors reviewed the circumstances and operators' response to the

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May 18,1999, plant trip. The inspectors interviewed operations and maintenance personnel and reviewed the following documents:

Fermi 2 Power Plant Sequential Events Recorder Log,

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Condition Assessment Resolution Document (CARD) 13885, " Manual Reactor

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Scram Upon Loss of Recirculation Pump A,"

Post Scram Data and Evaluation Report 99-001,

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General Electric Transient Analysis Report Traces, and

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Updated Final Safety Analysis Report Figure 4.4-3, " Typical Power / Flow

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Operating Map."

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Observations and Findinas While workers were performing maintenance on the motor generator (MG) set for Reactor Recirculation Pump A, an exciter field brush came into contact with the center slip ring and caused a short circuit. Mechanics had been in the process of replacing the brushes. The short circuit caused a generator lockout relay trip that tripped the recirculation pump. Reactor power remained at 97 percent as core flow dropped to 40 percent, thereby placing the reactor in the scram region of the core flow to power map.

The operators entered Abnormal Operating Procedure 20.138.01," Recirculation Pump Trip 'A,'" and appropriately placed the mode switch to the " shutdown" position and tripped the reactor. All rods inserted as expected. No emergency core cooling systems actuated and no safety relief valves lifted.

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Plant equipment responded as expected following the reactor scram. After the plant was stable in Mode 3 (Hot Shutdown), licensee management held a meeting to discuss the required actions for retuming the plant to full power operation. The inspectors attended the meeting. The license staff effectively reviewed and prioritized actions that needed to be completed prior to plant restart. Completed actions included evaluating the trip per the transient analysis program, determining the root cause of the short circuit in the MG set for the recirculation pump, satisfying post-shutdown and pre-startup TS required surveillances, and conducting equipment repairs and forced outage maintenance activities. The inspectors determined that the licensee's investigation was timely and thorough. In addition, activities to restart the plant were well coordinated.

The licensee determined the cause of the short circuit to be related to a design modification completed during Refueling Outage 6. The modification was intended to improve.the process of replacing the field brushes with the plant online.. The modification included adding a vamish insulation covering to prevent accidental short

- circuiting between bus bars. The short circuit that caused the trip of the MG set occurred on the vamished portion of the bus bar. The licensee sent a sample to the laboratory for testing and found that the coverage of the vamish was not adequate to provide the diatelectric needed to prevent a short circuit between the bus bars.

The licensee performed the following corrective actions:

yThe preventive maintenance task to change the MG set brushes was revised to

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inspect the brushes and only change them with approval of maintenance management; The method for changing the brushes was revised to reduce the chance of

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causing a short circuit; and An action was included in the corrective action program to evaluate options for

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improving the ability of successfully changing the MG set brushes with the plant on line.

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Conclusions Operators took prompt and appropriate action to scram the plant when the reactor entered the scram region of the power to flow map upon the loss of a reactor recirculation pump. Plant equipment responded as expected. Activities to restart the plant were well coordinated. The licensee's investigation of the cause for the recirculation pump trip was timely and thorough.

01.2 Restart of Unit Followina Manual Plant Scram a.

Insoection Scoos (71707)

The inspectors observed plant restart activities, including attending pre-evolution briefs and shift tumovers following the reactor scram described in Section 01.1 above. The inspectors also reviewed Procedures 22.000.02, " Plant Startup to 25 Percent Power,"

and 22.000.03, " Power Operation 25 Percent to 100 Percent to 25 Percent."

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Observations and Findinas The inspectors observed that shift turnovers and pre-evolution briefs were thorough and were in accordance with operations department policies. The briefs and tumovers were attended by requisite personnel participating in the evolution. In general, communication among operators met management expectations.

Operators increased plant power in a controlled and deliberate manner. The licensee identified several equipment deficiencies during startup that included: (1) The inability to withdraw Startup Range Monitor A: (2) Two inoperable offgas system condenser fans; and (3) A failed motor support structure for the gland steam system bypass valve. The licensee satisfactorily resolved these deficiencies prior to continuing startup. The inspectors also reviewed systems listed in the limiting condition for operation (LCO)

logbook for mode restraints and verified that no mode restraints existed.

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Conclusions Operators conducted the plant restart in a controlled and deliberate manner following the May 18,1999, plant trip. Shift tumovers and pre-evolution briefs for the power escalation were thorough and were conducted in accordance with operations department policies.

01.3 Operator Resoonse to Heat Exchancer Foutina a.

Inspection Scope (71707)

The inspectors reviewed the licensee's response to fouling of various nonsafety-related heat exchangers. The inspectors' review included control room logs, corrective action documents, various procedures, and interviews with operations and maintenance personnel.

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Observations and Findinas Between June 5 and 12,1999, the licensee identified fouling of the turbine and reactor building closed cooling water heat exchangers, and the main turbine lube oil and hydrogen heat exchangers. The licensee determined the fouling to be attributable to zebra mussel infestation, a sudden increase in lake temperature, and flow perturbations in the GSW system.

Licensee personnel from the engineering, operations, maintenance, and radiation protection organizations exhibited good coordination to clean the heat exchangers with the plant online. The licensee performed the work without incident. Operators reduced reactor power to 78 percent to allow cleaning of the main turbine hydrogen heat exchangers. The power reduction was accomplished deliberately and without incident.

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The licensee initiated corrective action documents (CARDS 99-14374 and 99-14254) to

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track corrective actions regarding fouling of the heat exchangers.

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Conclusions Operators responded effectivel'y to several fouled heat exchangers cooled by the GSW system. Corrective maintenance activities were well planned and executed. There was

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good coordination among personnel from the engineering, operations, maintenance, and radiation protection organizations.

.02 Operational Status of Facilities and Equipment O2.1 Enaineered Safetv Feature System Walkdowns (71707)

The inspectors used Inspection Procedure 71707 to walk down accessible portions of the following engineered safety feature systems and high risk equipment areas:

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RHR Complex, High Pressure Coolant injection Room,

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Divisions 1 ans 2 Switchgear Rooms,

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Control Room,

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GSW Pump House

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. Equipment operability, material condition, and housekeeping were acceptable in all cases. Several minor discrepancies were brought to the licensee's attention and were corrected. The inspectors identified no substantive concerns as a result of these.

walkdowns.

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Miscellaneous Operations issues (92700)

08.1 {Qggn) Unresolved item 50-341/99007-01: Conduct of a Emergency Diesel Generator (EDG) 11 Maintenance Activity with Standby Liquid Control (SLC) Pump B Inoperable.

On May 5,1999, the inspectors identified that the licensee had removed the Division 1 EDG 11 for maintenance while the Division 2 SLC system was inoperable.

Division l SLC System A and Division 2 SLC System B are powered by Division 1 EDG.11 and Division 2 EDG 13, respectively. With neither SLC B nor EDG 11 available, a method of injecting Boron into the core may not have been available during a loss of offsite power event.

Technical Specification 3.8.1.1.c requires, in part, that with one or both EDGs inoperable, verify within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> that all required systems, subsystems, trains, components and devices that depend on the remaining onsite attemating current electrical power division as a source of emergency power are also operable; otherwise, be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

On May 25,1999, the licensee completed the evaluation of TS 3.8.1.1.c applicability, as documented in CARD 99-13518. The licensee determined that TS 3.8.1.1.c did not apply to the SLC system, contrary to the inspectors' concems.' The NRC staff is in the process of reviewing the licensee's basis for their determination regarding TS 3.8.1.1.c applicability. The results of the NRC staffs review will be documented in a future inspection report.

During this inspection period, the inspectors reviewed licensee staff performance in communicating and managing plant equipment configuration. The inspectors interviewed associated personnel and reviewed the following documents:

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Control Room Logs Between May 3 and May 5,1999,

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NRC Inspection Manual Part 9900: " Technical Guidance for Resolution of

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Degraded and Non Conforming Conditions," and " Technical Guidance for Operable / Operability: Ensuring the Functional Capability of a System or Component,"

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CARD 99-13518, " Failure to Enter TS Action Statement,"

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CARD 99-13512, "SLC System B Continuity Loss,"

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. Technical Manager Inservice Inspection Memoranda 99-0138, " Risk Assessment

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of EDG 11 System Outage,"

Safety Tagging Record (STR) 99-0474, "Tagout to Troubleshoot Repeated

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Opening of Squib Continuity Monitor Fuse F-4,"

TS Action 3.8.1.1c., " Electrical Power - Alternating Current Sources,

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TS Action 3.1.5.a.1, " Reactivity Control System - SLC,"

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Engineering Functional Analysis for SLC System with Non-Operational Continuity

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Indication dated May 5,1999, Schematic Diagram 61721-2131-01, "SLC Pumps C4103C001 A & B,"

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Engineering Support Conduct Manual MES27, Revision 5, " Verification of

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System Operability," and Operations Conduct Manual MOP 05, Revision 7 " Control of Equipment."

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On May 3,1999, at 6:30 p.m., the fuse in the Division 2 SLC B squib valve monitoring circuit opened and caused a control room annunciator to actuate. The monitoring circuit assures squib valve integrity by trickling a low amperage current through the squib elements. The licensee documented the condition on CARD 99-13512, declared SLC B system inoperable, and entered a 7-day LCO per TS 3.1.5.a (LCO 99-0197).

On May 4,1999, at 2:23 a.m., operators reviewed EDG 11 Maintenance Rule Chapter 12, Section 5.4, (Technical Manager Inservice Inspection Memoranda 99-0038)

for a preplanned 4-day maintenance activity on EDG-11. The operators determined the risk to be low. The operators recognized that SLC B was inoperable, but considered it functional. This was based on the conclusion that the SLC B system would actuate with the fuse open in the squib valve monitoring circuit. The operators reviewed the TS and concluded that TS 3.8.1.1.c did not apply because the operators considered the SLC system non-divisional since it did not meet separation criteria (a common SLC tank, piping and no barrier between SLC pumps) and that the SLC system was not required to mitigate a design basis accident.

Although control room operators discussed amongst themselves and the operations engineer, the acceptability of removing the EDG from service with the SLC B pump inoperable, they did not to consult with engineering personnel in deciding that TS 3.8.1.1.c did not apply to this situation. Contributing to the uncertainty regarding this issue, was the lack of a formal checklist of opposite division equipment to be verified as operable in this configuration. A checklist may have been useful in clearly delineating to the operators what equipment was required. Therefore, the licensee did not perform the 2-hour verification as required by the TS. On May 4,1999, at 3:00 a.m., the licensee declared Division l EDG 11 inoperable.

I Subsequently, attempts to replace the fuse on the squib continuity circuit were i

unsuccessful. The licensee later determined that there was a ground on an ammeter in

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the circuit. On May 4,1999, at 6:35 p.m., operators tumed off power and tagged open Motor Control Center 72E-5B Position 28 in accordance with Safety Tagging Record

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(STR) 99-0474 in preparation to troubleshoot the squib continuity monitor fuse. Turning

' off the breaker caused power to be unavailable to SLC Pump B, rendering the pump functionally unavailable. As discussed above, earlier in the day, the operators considered the SLC B pump inoperable, but functional. Once power was removed by the STR, the configuration of the SLC B system was changed to being inoperable and

' not functional. This change in configuration was not logged or documented. The occurrence of this problem indicated a weakness in the control room operator's control and communication of plant configuration.

On May 5,1999, at approximately 8:20 a.m., the inspectors reviewed TS 3.8.1.1.c and were concerned that the licensee did not meet the associated TS actions. The inspectors informed the licensee. Delays occurred in relaying this concem to the shift supervisor due to ongoing intemal licensee meetings. Consequently, control room -

operators did not receive this information until approximately 10:15 a.m. that same day.

To meet the TS action statement, management directed control room operators to commence preparations for an orderly shutdown. In parallel, operators cleared STR tags to close the breaker for SLC Pump B for restoring system operability. The TS action statement was met on May 5,1999, at 10:32 a.m. after tags were cleared to close the breaker for Motor Control Center 72E-5B Position 28 and provide power to SLC Pump B. in addition, the operators consulted with engineering and maintenance personnel and determined that the SLC B system was operable even with the squib i

l-continuity ammeter fuse open. Later that same day, the licensee completed an engineering functional analysis for the SLC system, which formally justified that the SLC system remtined operable with a non-operational squib valve continuity indication circuit.

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l The inspectors reviewed Schematic Diagram 61721-2131-01, "SLC Pumps," and verified that the open fuse did not impact the ability for the system to actufca. The inspectors also reviewed Engineering Support Conduct Manual MES27, Revision 5,

" Verification of System Operability," and Operations Conduct Manual MOP 05,

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l Revision 7, " Control of Equipment," to determine the requirements for declaring equipment operable. Neither procedure required that an engineering functional analysis i-be completed before declaring SLC System B operable. The shift supervisor generally made the operability determination.

I Further, NRC Generic Letter 91-18, Revision 1, "Information to Licensees Regarding l

NRC inspection Manual Section on Resolution of Degraded and Nonconforming Conditions," required that operability determinations be performed promptly but was not l

explicit in requiring that formal documented evaluations be completed and finalized prior I

to the operability of a component being determined.

The licenses initiated a high priority investigation (CARD 99-3518) to document the

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failure to enter TS Action 3.8.1.1.c. A solution team was formed to perform the CARD investigation and the team developed a basis that TS 3.8.1.1.c did not apply with the

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SLC B and EDG 11 inoperable. NRC review of the applicability of TS 3.8.1.1.c to SLC is in progress and, as a result, this Unresolved item, will remain open.

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Conclusions.

The plant configuration with the removal of EDG 11 from service with opposite division SLC System B inoperable raised a TS 3.8.1.1.c compliance question which is being tracked as an Unresolved item. The inspectors determined that contributing to the uncertainty regarding the applicability of TS 3.8.1.1.c to SLC equipment, was the lack of i

I procedural guidance regarding what equipment was required per this TS. Also, control room operators did not communicate effectively with management or engineering personnel in determining whether TS 3.8.1.1.c was applicable to the standby liquid control systems, prior to removing EDG 11 from service for maintenance. As a result.

- once this configuration was questioned by the NRC, prompt actions were initiated which included briefing for a controlled plant shutdown. These actions, though appropriate and timely, could have been avoided if the applicability of TS 3.8.1.1.c was thoroughly evaluated prior to the plant being placed in a questionable configuration. Weaknesses were also noted regarding documentation and communication of equipment status.

~ Opecifically, control room operators did not document or communicate changes in the functionality of the standby liquid control system when power was removed to support trouble shooting activities.

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11. Maintenance M1 Conduct of Maintenance M1.1; Main Steam Line "B" Steam Flow Indication Readina L6wer Than Expected a.

Insoection Scooe (62707)

The inspectors reviewed the licensee's troubleshooting and repair of "B" steam flow indication.

The inspectors reviewed the following documents:

Control Room Logs

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CARD 99-13778 Technical Procedure 23.107, " Reactor Feedwater and Condensate System"

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Applicable Radiation Work Permit Requirements

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WR 000Z991855, " Steam Flow Indication for Main Steal Line "B" Reading Lower

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than Expected" Work Control Conduct Manual MCWO2, " Work Control"

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CARD 99-14188, "Feedwater Master Controller Would Not Go in Automatic

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Observations and Findinos The inspectors reviewed the WR against Procedure MCWO2,'and found the WR was developed per the procedure. The inspectors attended the pre-job brief for troubleshooting the circuit.' The operators performed the brief per ODI 37, " Pre-Job Briefs," and Section 2.7 of Operations Conduct Manual MOP 03, " Policies and Practices." '

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The inspectors also observed the troubleshooting of the power supply circuitry and the transmitter. Instrumentation and control (I & C) technicians determined that the square root converter was defective. The technicians replaced the converter and performed post-maintenance testing of the circuit. Testing was successful. The inspectors identified no concerns.

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Conclusions

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The pre-job brief and the coordination of troubleshooting activities for repairing a failed square root converter for the feedwater master controller were effective. The work package was properly prepared in accordance with the work control procedure.

M1.2 Resolution of Calibration Problem a.

Inspection Scope (62707)

The inspectors reviewed licensee actions to resolve a procedure deficiency involving Task ID IC0741, " Loop Cal Check Reactor Pressure Vessel Jet Pump 11 Pressure / Flow

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Indicating System."

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Observations and Findinos The licensee generated Task ID IC0741 to apply a different calibration tolerance methodology towards the calibration check of the reactor pressure vesseljet pump pressure / flow indicating system. During the performance of Task ID IC0741, l&C technicians determined that the instrumentation string tolerances were small and that the system string needed to be calibrated.

Upon further review, the l&C technicians noted a potential error in the associated design calculation (DC) calibration table. Engineering, l&C supervision, and operations supervision personnel discussed the issue and determined that engineering personnel

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did not correctly convert mass flow rate error to an electrical current error. The error

was determined to be in the conservative direction and did not affect the operability of the instrument string. The licensee initiated CARD 99-14420 to document error. The licensee corrected the field calibration table and the technicians successfully checked the jet pump flow strings.

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Conclusions Instrumentation and Controls personnel demonstrated a good questioning attitude and e#ectively resolved a calibration problem with a jet pump flow instrumentation string.

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E3 Engineering Support of Facilities and Equipment E3.1 Effective Encineerino Suocort of Plani Activities (37551)

The inspectors reviewed a sampling of evaluations that supported plant modifications, engineering functional analysis, and configuration risk management program

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l evaluations for removing equipment from service. The inspectors determined these documents to be thorough. The inspectors noted effective engineering support during 1-

. scheduled maintenance activities and in assisting root cause determinations for events

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involving the reactor trip and fouling of GSW coolers. Although the inspectors noted that engineers were not routinely present during control room shift tumovers, engineers were involved in the plant management meetings for discussing system planned outages and in discussing plant issues.

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l E8 Miscellaneous Engineering issues (92903)

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E8.1. [ Closed) Licensee Event Reports 50-341/97006-00 and 97006-01: " Response Time Testing Not in Conformance with TS." The licensee determined that response time testing was not conducted once per 18 months per TSs 4.3.1.3,4.3.2.3 and 4.3.3.3 for l

.each reactor protection system trip functional unit, the isolation system trip functional

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unit, and for the emergency core cooling system trip function, respectively. This occurred during an evaluation in a Boiling Water Reactor Owner's Group licensing i

~ topical report that identified the response time limit tables be moved from the TS to the

Updated Final Safety Analysis Report. During this review, the TS definitions were not l

identified as affected and, therefore, the report did not recognize that a TS change was required. A TS change'was requested and TS Amendment 111 was issued. This issue was addressed in Inspection Reports 50-341/970011,98005, and 99002; subsequently escalated enforcement item 50-341/98005-04 was issued.

E8.2 (Closed) Insoection Followuo item 50-341/96201-04: Improper Setpoint for High Pressure Coolant injection Pump (HPCI) Suction Low Pressure Trip. The NRC safety system inspection team determined that HPCI pump cavitation would occur well before l

the low suction pressure of 15 inches Hg vacuum trip / alarm setpoint actuated. The licensee initiated Deviation Event Report (DER) 96-1191 for this finding. During their

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investigation of this DER, the licensee reviewed the following:

HPCI System's General Electric Design Specification 22A1362, Revision 6; l

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General Electric Design Specification Data Sheet 22A1362AR, Revision 11;

System Design Basis Document E41-00;

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Alarm Response Procedures 2D55,2D64,2D89, and 2D99;

HPCI Quick Start Results;

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Design Calculation 501; i

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Isometric Drawings; and

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a Based on a review of the documents, the licensee determined from Data Sheet 22A1362AR that the HPCI system required a minimum net positive suction head (NPSH) of P.1 feet to prevent cavitation. Design Calculation 501 indicated 37.2 feet of NPSH was available for the pump, which was higher than the low suction pressure alarm of 15 inches Hg vacuum. The licensee concluded that since operators monitored and maintained the condensate storage tank !evel, sufficient NPSH was available. The purpose of the alarm was to protect the pump in the event vacuum developed because of a blocked suction pipe while HPCI received suction from the suppression pool or the condensate storage tank. The inspectors reviewed the licensee's evaluation and had no

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y E8.3 (Closed) Insoection Followuo item 50-341/96201-06: Verify Coordination of Fuses. The NRC Safety System Function inspection Team identified that the fault currents had not been calculated in DC 2913. Specifically, the team questioned whether Fuse FRN-R-15 rated at 15 amperes at Distribution Panel 2PB2-6 (used for nonsafety and safety loads)

and Fuse KLM-10 rated at 10 amperes at Panel H11-P620 would coordinate for a fault of 2700 amperes. A fault in any nonsafety-related loads in the circuit protected by a 10-ampere fuse could cause a less of the HPCI turbine control which has no redundancy.

The licensee pArformed a calculation and contacted the vendor. Since the vendor usually does not test these fuses for coordination, the vendor indicated that it would not be possible to predict whether the fuses would coordinate. The licensee initiated DER 96-1128 for this finding.

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As corrective action for the DER, the most conservative fault currents were determined for various fuse coordination in DC 2913. Ter.,t requisitions were issued to test the coordination between several combinations of fuses at the most conservative available sho t circuit currents for circuits in the plant. The test results were documented in Engineering Service Organization Report 96J75-57 and the test demonstrated that the

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fuses were coordinated. The inspectors reviewed the licensee's evaluation and had no concerns.

IV. Plant Support

R1 Radiological Protection and Chemistry Controls R1.1 Effective Suooort Bv Radiation Protection (71750)

During routine tours the inspectors verified that the radiological survey equipment was within the calibration dates. The inspectors observed the licensee staff effectively using survey equipment when exiting radiological areas. Also, radiation protection personnel were observed promptly responding to survey equipment that became out of service.

Inspectors observed routine plant activities and noted radiation department support during those activities. A representative from the radiation department attended the control room shift turnover and effectively participated in the tumovers.

V. Manaaement Meetinas X1

. Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the

conclusion of the inspection on June 18,1999. The licensee acknowledged the findings

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presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

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PARTIAL LIST OF PERSONS CONTACTED Licensee S. Booker, Work Control D. Cobb, Superintendent, Maintenance J. Davis, Nuclear Training J. Davis, Outage Management P. Fessler, Plant Manager R. Gaston, Supervisor, Compliance D. Gipson, Senior Vice-President, Nuclear Operations K. Hlavaty, Superintendent, Operations K. Howard, Plant Support, Engineering.

A. Kowalczuk, Manager, Plant Support -

P. Lynch, Work Control, Operations E. Meyer, Nuclear Shift Supervisor J. Milton, Nuclear Security J. Moyers, Director, Nuclear Quality Assurance W. O'Connor, Assistant Vice-Ptesident, Nuclear Assessment N. Peterson, Acting Director, Nuclear Licensing J. Plona, Manager, Technical

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K. Sessions, Maintenance I

P. Smith, Licensing S. Stasek, Supervisor, Independent Safety Engineering Group D. Williams, Radiation Protection NRL S. Campbell, Senior Resident inspector A. Vegel, Chief, Reactor Projects Branch 6

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ITEMS OPENED, CLOSED AND DISCUSSED

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Opened None

~G9Ed 50-341/97006-00 LER Response Time Testing Not in Conformance with TS 50-341/97006-01 LER Response Time Testing Not in Conformance with TS 50-341/96201-04 IFl improper Setpoint for HPCI Pump Suction Low Pressure Setpoint 50-341/96201-06 IFl Verify Coordination of Fuses Discussed 50-341/99007-01 URI EDG 13 Maintenance Activity with SLC Pump B inoperable INSPECTION PROCEDURES USED IP 37551:

Onsite Engineering IP 62707:

Maintenance Observation IP 71707:

Plant Operations

~ IP 71750:

Plant Support Activities IP 92700:

Onsite Follewup of Written Reports o' Nonroutine Events at Power Reactor Facilities IP 92903 Followup - Engineering LIST OF ACRONYMS USED i

CARD Condition Assessment Resolution Document DC Design Calculation DER Deviation Event Report EDG Emergency Diesel Generator GSW General Service Water i

HPCI-High Pressure Coolant injection j

l&C Instrumentation and Control LCO Limiting Condition for Operation MG Motor Generator NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission ODI Operations Department instructions RHR Residual Heat Removal SLC Standby Liquid Control STR Safety Tagging Record TS Technicel Specification WR

- Work Request i

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