IR 05000263/1999002

Insp Rept 50-263/99-02 on 990223-0408.One Violation Occurred & Being Treated as non-cited Violation.Major Areas Inpsected:Operations,Engineering,Maint & Plant Support

ML20206G783
Person / Time
Site:	Monticello
Issue date:	05/03/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20206G779	List: IR 05000263/1999002 ML20206G774
References
50-263-99-02, 50-263-99-2, NUDOCS 9905100142
Download: ML20206G783 (15)

Text

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U. S. NUCLEAR REGULATORY COMMISSION

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Docket No: 50-263 License No: DPR-22 Report No: 50-263/99002(DRP)

Licensee: Northern States Power Company Facility: Monticello Nuclear Generating Station Location: . 2807 West Highway 75 Monticello, MN 55362 Dates: February 23 through April 8,1999 Inspectors: S. Burton, Senior Resident inspector D. Wrona, Resident Inspector Approved by: Roger D. Lanksbury, Chief Division of Reactor Projects Branch 5 9905100142 PDR 990503 U 0 ADOCK 05000263 PDR

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EXECUTIVE SUMMARY

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. Monticello Nuclear Generating Station NRC Inspection Report 50-263/99002(DRP) i l

This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection.

' Ooerations

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The licensee's initial operability determination conducted for a degraded bellows leak detection system for a safety relief valve was not thorough.' The subsequent review,-

performed after the inspectors raised concerns, was thorough and appropriately concluded the valve was operable. ' (Section 01.2)

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The licensee properly responded to a momentary increase in the drywell unidentified leak rate. The inspectors found the evaluation and the determination of the cause to be comprehensive and accurate. (Section O1.3)

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A loss of the safety parameter display system associated with an unplanned outage of

. the plant process computer was reported to the NRC headquarters operations center in accordance with plant procedures. The inspectors found that procedures and reporting

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requirements were appropriate.--(Section 01.4)

• Various temporary scaffolding assemblies had been installed for extended periods of time. The inspectors were concerned that this scaffolding could affect the operability of nearby equipment in the event of a seismic disturbance. (Section O2.1)

- A licensee review of shift technical advisor training indicated that shift technical advisors were trained and qualified as required by the associated training program. Inspectors sampled the requirements and found no deficiencies. (Section 05.1)

Maintenance l l

• - The inspectors noted a deficiency with the level of detail of instructions in the procedure j followed for the calibration of relays associated with the safeguard bus degraded voltage l

. protection, in that a short duration,125-volt direct current ground resulted and relay l l

technicians experienced difficulty in the setup of the voltage test source. (Section M1.3)

-* Replacement of a control rod drive hydraulic accumulator level switch was performed by knowledgeable technicians who followed instructions in approved procedures. ' When the inspections of pressure switch intemals indicated past leakage, the system engineer demonstrated good follow-through by having technicians inspect other instruments to aid in determining the extent of the problem. (Section M1.4)-

. Enaineerina j

+ Engineering and safety evaluations for inhibiting the reactor protection system bypass function for the turbine stop valve closure and turbine control valve fast closure scram were comprehensive. No safety significant issues were identified. Engineering and .

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supervisory involvement were observed throughout the evolution. (Section E1.1)

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Report Details Summary of Plant Status

. The Unit operated at approximately 100 percent power for most of the report period. On i March 15,1999, power was briefly reduced to approximately 98.5 percent due to a loss of the plant process computer. On March 27, power was reduced to approximately 60 percent power l

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to perform a control rod sequence exchange and various other tasks. The Unit was returned to approximately 100 percent power on March 28.

1. Operations 01 Conduct of Operations 01.1 General Comments (71707)

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The inspectors observed various aspects of plant operations, including compliance with Technical Specifications (TSs); conformance with plant procedures and the Updated Safety Analysis Report (USAR); shift manning; communications; management oversight; proper system configuration and configuration control; housekeeping; and operator performance during routine plant operations, the conduct of surveillance tests, and plant power changes.

The conduct of operations was professional and safety conscious. Evolutions such as surveillance tests and plant power changes were generally well controlled, and deliberate, and were performed in accordance with procedures. Shift tumover briefings I were comprehensive and were typically attended by the operations superintendent and i representatives from the scheduling, security, instrument and control, electrical, and mechanical maintenance departments. Housekeeping was generally good and discrepancies were promptly corrected. Safety systems, including the #11 emergency diesel generator, were found to be properly aligned. The inspectors performed spot checks of " hold" and " secure" cards installed as isolation for various maintenance items and had no concerns. Minor issues, such as a missing equipment identification tag and a ladder not properly secured, were brought to the attention of the licensee and were l promptly corrected. Specific events and noteworthy observations are detailed below. j

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01.2 Leak in Safety Relief Valve Bellows Monitorino System a. Inspection Scooe (71707)

On March 25,1999, safety relief valve (SRV) "G" was declared inoperable and L TS 3.6.E.1 was entered. Inspectors reviewed the reason for entry into the TS, Condition Report 99000808 and the associated operability, maintenance rule requirements, and USAR Section 4.4, " Reactor Pressure Relief," to assess the impact on overall plant operation and safety, b. Observations and Findinos The ."G" SRV was declared inoperable after the licensee noted indications of a possible j

malfunction or leak during a surveillance test of the valve bellows leak detection system.

The inspectors performed a review of related requirements and references and

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identified that the operability determination did not address several pertinent items:

USAR requirements relating to the ability of the system to detect leakage; the range of

' leaks that was undetectable; TS requirements for an operable leakage detection system; and the ability to perform TS surveillances tests given a potentially degraded leakage detection system. The items were discussed with the licensee who subsequently conducted a further review and developed a special test to further evaluate the condition. The inspectors attended the operations committee review of the special test procedure and noted the committee conducted a thorough review of the procedure, asked probing questions, and recommended changes to align the procedure with TS. The licensee planned to document the results of further testing and evaluation in the associated condition report.

- c. Conclusions i The licensee's initial operability determination conducted for a degraded bellows leak )

detection system for a safety relief valve was not thorough. The subsequent review, i performed after the inspectors raised concems, was thorough and appropriately concluded the valve was operable.

01.3 Momentarv increase In Drywell Unidentified Leak Rate a. Inspection Scope (71707) ,

On April 1,1999, the licensee had a momentary increase in the unideniified drywell leak rate that exceeded six gallons per minute. The inspectors reviewed the TSs, USAR, and the associated operability determination to assess impact on plant safety, b. Observations and Findinos On April 1,1999, a momentary increase in drywell unidentified leak rate, as indicated from equipment associated with the drywell floor drain tank, occurred on two occasions.

Operators were alerted to the increase via an associated alarm in the control room.

Further investigation found that the drywell floor drain sump pump discharge check valve was stuck open or partially open. Due to system configuration, this condition resulted in water back-flowing into the sump from the reactor building floor drain tank when pumped or from the floor drain collector tank, which is the common discharge point for both of these sumps. The inspectors reviewed the TS requirements, an .

operability determination, and testing performed to demonstrate that the source water l was due to backflow into the drywell floor drain tank. The inspectors found the ,

evaluation and the determination of the cause to be comprehensive and accurate.

- c. Conclusions

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' The licensee properly responded to a momentary increase in the drywell unidentified leak rate. The inspectors found the evaluation and the determination of the cause to be comprehensive and accurate. l

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01.4 Loss of Plant Process Comouter. Safety Parameter Disolav System. and 3D-Monicore Computer l a. Inspection Secoe (71707)

The inspectors reviewed the licensee's response to a loss of the plant computers.

Included was a review of reporting requirements, operating procedures, and operator logs.

b. Observations and Findinas On March 15,1999, the licensee's computer systems for the safety parameter display system (SPDS) became inoperable due to a computer fault. The licensee immediately contacted the computer department to respond to, and correct the condition. Operators reduced power to 610 megawatts electrical and performed a heat balance per Operations Manual C2.-01, Revision 10, " Power Operation," Section D.2.a. The inspectors reviewed the reportability guidelines in 10 CFR 50.72; NUREG 1022, Revision 1, " Event Reporting Guidelines 10CFR 50.72 and 50.73"; and licensee Administrative Work Instruction, (AWI)-04.08.01, Revision 15, " Event Notifications."

awl-04.08.01 indicated that a loss of SPDS required a courtesy call to the NRC if the system is anticipated to be out-of-service for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The inspectors reviewed the basis for classifying an SPDS outage as not reportable. The licensee indicated that SPDS was an enhancement to plant operations and that the system was not relied upon for performance of emergency operating procedures or accident '

assessment. Additionally, the emergency operations facility and technical support centers communicators were constantly in contact with the control room during an event and maintain information boards, which duplicate the information available on SPDS.

Interviews with the training department indicated that simulator training for operators was periodically conducted without the process computer to verify that accident assessment and response could be performed without the aid of the system. The licensee made a " courtesy call" to the NRC operations center approximately 1.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after the initiation of the event. Inspectors reviewed the reportability requirements with NRR and found no deficiencies.

c. Conclusions A loss of the safety parameter display system associated with an unplanned outage of the plant process computer was reported to the NRC headquarters operations center in accordance with plant procedures. The inspectors found the procedures and reporting requirements appropriate.

O2 Operational Status of Facilities and Equipment )

O2.1 Scaffoldina a. Inspection Scope (71707)

During routine tours of the reactor t,uilding the inspectors noted that some temporary scaffolding had been in place for an extended period of time. Included as part of this inspection were discussions with maintenance and engineering personnel, and a review of the following documents:

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= 4AWi-04.05.10, Revision 3, " Scaffolding Controls"

= Procedure 8146, Revision 11, " Scaffold Control"

=- Scaffold Control Log b. Observations and Findinas The inspectors noted that various temporary scaffolding assemblies had been installed for extended periods of time. For example, scaffolding had been installed in the torus catwalk area, "B" residual heat removal room, and in the high pressure coolant injection room since January 1997, to allow electricians to perform monthly maintenance checks on temporary lighting panels. The inspectors noted that a safety review was not completed for these scaffolding assemblies and Procedure 8146 only required that a safety review be performed "if the proposed scaffold installation will impact equipment operability, or will be attached to safety-related systems, or will be installed above safety-related equipment with the combined weight of the scaffold, equipment, and personnel exceeding 1500 lbs (pounds)."

The inspectors questioned the licensee to determine if there was a time limit on how long scaffolding would be installed and the basis for the 1500 lbs limit as stated above.

The licensee had no established time limit and had no written basis for the 1500 lbs, j although it believed that the value was based on the station definition of a heavy load, j 1500 lbs. i The inspectors noted that no formal process existed to periodically inspect the scaffolding to ensure it remained properly installed. The inspectors also noted that the

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licensee's definition of a temporary modification did not include temporary modifications to structures. The inspectors were concerned about the effect that this scaffolding could have on the continued operability of nearby equipment in the event of a seismic disturbance. The licensee has initiated Condition Report 99000954, "Concems Over Adequacy of Scaffolding Controls," to address these issues. This item is considered an inspection followup item (IFl 50-263/99002-01(DRP)) pending inspector review of the results of the licensee's evaluation.

c. Conclusions Various temporary scaffolding assemblies had been installed for extended periods of time. The inspectors were concerned that this scaffolding could affect the operability of nearby equipment in the event of a seismic disturbance.

05 Operator Training and Qualification 05.1 Shift Manaaer/ Shift Technical Advisor (STA) Qualifications a.' Insoection Scope (71707)

The inspectors reviewed the qualification requirements for shift managers / STAS in order to verify that the licensee's program adhered to Technical Specifications requirements. l

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. b. ' Observations and' Findinas

. During a routine review of condition reports, the inspectors noted that Condition Report 99000403 noted a discrepancy between the STA training program requirements and qualifications. The condition report indicated that there was a requirement for a biennial examination and that the examination had not been given. Technical I Specification 6.1.C.1 requires that a qualified STA be assigned to each operating shift during power operations. Inspectors reviewed the condition report and the i requirements, and discussed STA qualifications with training department management.

The inspectors identified that the senior reactor operator examination had been substituted for the STA examination and that this had been evaluated and found acceptable by the licensee. The condition report accurately reflected this change and noted that, although previously approved, procedures had not been appropriately updated to reflect changes in program requirements.-

Additionally, the inspectors inquired as to the correlation of the balance of the STA program requirements and if the program had been completed. The licensee reviewed

the STA program and compared the training to the requirements and found no deficiencies.

c. Conclusions A licensee review of shift technical advisor training indicated that shift technical advisors were trained and qualified as required by the associated training program. Inspectors sampled the requirements and found no deficiencies.

11. Maintenance M1 Conduct of Maintenance M1.1 General Comments on Maintenance Activities a; Insoection Scope (62707)  !

l The inspectors observed ' performance of all or portions of the activities contained in i following work orders (WOs): {

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. WO 9904298, " Correct 11 SW [ service water] Pump Discharge Pressure Strain," j performed on March 3,1999.

. WO 9904091, "A Gezip Pump Will Not Pump at Full Capacity," performed on March 3,1999.

• WO 9904158, " Remove Plate & Bolt from Jet Pump Hold Down Beam,"

performed on March 3,1999.

- Procedure 7180, Revision 13, " Diesel Generator System Instrument ,

Maintenance Procedure," performed on March 9,1999. I

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• WO 9904235, " Repair Damaged Pressure Regulator Gauge," performed on March 15,1999.

. WO 9904462, " Swap Breaker Serving Cubicle 152-607," on March 17,1999.

'. WO 9803311. " investigate Spurious Residual Heat Removal Alarm C03-A-3,"

performed on March 19,1999.

• - Procedure 4510PM, Revision 10, " Maintenance of On-site Batteries and Battery Chargers at Monticello Nuclear Plant," performed on March 22,1999.

b. Observations and Findinos The inspectors found the work performed in these activities to be professional and thorough. All work was performed in accordance with procedures and the workers were

' knowledgeable on their assigned tasks. When applicable, test equipment was within

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calibration, radiation protection staff were present, and radiological work permits were followedc The inspectors observed supervisory and engineering involvement in the activities and adequate foreign material exclusion controls. Proper authorizations were obtained prior to commencing work.

M1.2 General Comments on Surveillance Test Activities 1 inspection Scooe (61726)

The inspectors observed or reviewed the performance of all or portions of the activities contained in the following surveillance test procedures:

Chemistry Procedure 1.5.03, Revision 8, " Discharge Canal Sampling," on February 24,1999.

• Chemistry Procedure 1.3.39, Revision 2, * Multi-Channel Analyzer Operation / Gamma isotopic Analysis," on February 24,1999.

• Procedure 1024,' Revision 23, " Area Radiation Monitor Calibration," on February 25,1999.

• Procedure 0255-04-1 A-1, Revision 45, " Residual Heat Removal Pump and Valve Test," on March 19,1999.

• ' Procedure 0074, Revision 25, " Control Rod Drive Exercise," on March 20,1999.

• Procedure 0255-17-1 A-5, Revision 10, ." Alternate Nitrogen System Train A Valve Test," on April 2,1999, b. - Observation and Findinos in general, the inspectors found that the activities specified in the surveillance test procedures were performed in a professional and thorough manner and were completed in accordance with the applicable procedures. Personnel were knowledgeable and generally demonstrated effective three-way communications, self-checking, and

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peer-checking. When conducted, pre-job briefings were comprehensive. The inspectors frequently observed supervisors and system engineers monitoring job l

progress. - Quality control personnel were present whenever specified in a procedure.

When applicable, appropriate radiation control measures were in-place.

M1.3 'Safeauard Bus Dearaded Voltaaa Testina a. Inspection Scope (61723)

The inspectors reviewed USAR, Section 8.4, and TS, Section 3.2,G, associated with instrumentation for safeguard bus degraded voltage and loss of voltage protection. The inspectors also observed the performance of various activities specified by the following procedures:

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Surveillance Procedure 0301, Revision 24, " Safeguard Bus Voltage Protection Relay Unit Functional Test," performed on March 3,1999, and

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Surveillance Procedure 0302, Revision 12, " Safeguard Bus Degraded Voltage Protection-Relay Unit Calibration," performed on March 3, and re-performed on March 9,1999. )

b. Observations and Findinos At the safeguard busses, the system engineer was present and provided technical guidance to the technicians working on the relays. The inspectors noted that it took multiple attempts by the technicians to properly set up the voltage test source to supply ,

voltage with the needed accuracy. After the drop out and pickup voltages were determined, it again took two attempts for the technician to properly set up the voltage test source timer to correctly record the time delay associated with the drop out time delay of the degraded voltage relay. A problem earlier in the shift in which an incorrect test fixture was used caused a 125-volt direct current ground (documented in Condition Report 99000612), and resulted in enough of a delay that the calibration procedure {

could not be completed as scherfuled that day. On March 3, the licensee terminated {

activities described in Procedure 0302 after calibrating one relay. A temporary change was processed to perform activities described in Procedure 0301 for the one relay

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calibrated. Electricians performed the activities described in Procedure 0301 and no deficiencies were noted. The steps of Procedure 0302 did not go into sufficient detail concerning setting up the voltage test source and specifying which test block to use.

Although these items did not impact operability of the systems tested, they did result in a short duration,125-volt direct current ground and difficulty in the setup of the voltage test source. These two examples of lack of sufficient detail contained in procedures constitute violations of minor significance and are not subject to formal enforcement action, c. Conclusions The inspectors noted a deficiency associated with the level of detail of the procedure followed for the calibration of relays associated with the safeguard bus degraded voltage protection, in that a short duration,125-volt direct current ground resulted and relay ;

technicians experienced difficulty in the setup of the voltage test source.

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' M1.4 Replacement of Control Rod Drive (CRD) Accumulator Level Switch i i

a. Inspection ScoDe (62707)

The inspectors reviewed work orders, radiation work permits, equipment tagouts, drawings, and procedures and observed maintenance technicians involved with the replacement of pressure switch, PS 130-14-11, for CRD hydraulic accumulator 14-11.

b. Observations and Findinos While performing routine calibration of PS-130-14-11, the technicians found that they could not adjust the pressure switch to within allowable tolerances. Work Order 9904531 was initiated to replace the pressure switch. The inspectors observed switch replacement and found technicians knowledgeable of system, procedural, and radiation work permit (RWP) requirements. The associated system engineer was present and monitoring performance of the maintenance. Upon removal of the ,

instrument, the technicians noted that internal corrosion lines indicated that water had at '

one time filled the enclosure to approximately 50 percent of capacity. Related to this observation, the inspectors noted that the system engineer had technicians perform spot checks of instrumentation during routine calibration the following week to aid in determining if the condition was an isolated case or a recurring problem. Based upon this fact, the inspectors concluded that engineering personnel demonstrated a good review and follow-through of an off-normal condition. Initial inspections revealed that there may be some corrosion or moisture related buildup within the switch enclosura.

Instrument and control supervision indicated that inspections were planned for switches that have larger than average instrument drift documented in historical records.

c. Conclusions Replacement of a control rod drive hydraulic accumulator level switch was performed by knowledgeable technicians who followed instructions in approved procedures. When the inspections of pressure switch internals indicated past leakage, the system engineer demonstrated good follow-through by having technicians inspect other instruments to aid in determining the extent of the problem.

M1.5 CRD Instrument Preventative Maintenance (62707)

The inspectors observed portions of WO 9904492, " Perform instrument PM [ Preventative Maintenance) on CRD-W4 Instrument," performed on March 4,1999.

During performance of WO 9904492, instrument and control technicians isolated the pressure indicator, pressure switch, and leve! switch of the associated control rod drive accumulator. The inspectors questioned operators conceming the operability of the accumulator while the indicator and switches were isolated. The operators consulted with the engineering staff and determined that the pressure and level switches were not attendant instrumentation necessary for the accumulators to perform their safety function. Operators also stated that if pressure or level were out of the required range when the indicators and switches were restored to normal, an investigation would be 1 l conducted and the accumulator would possibly be declared inoperable. The inspectors had no further concems.-

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b-f, M8 Miscellaneous Maintenance issues (92700,92902) .

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M8.1 : (Closed) Violation (VIO) 50-263/98002-03(DRP): Failure to provide adequate )

. Instructions for lifting crates to the refueling floor. This violation is in the licensee's l corrective action program as Condition Report 98000165, " Lifted and moved fuel channels over refuel floor two at a time, creating heavy loads movements w/o required controls."

This Severity Level IV violation was issued in a Notice of Violation prior to the March 11, 1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because this violation would have been treated as Non-Cited Violation in accordance with Appendix C, it is being closed j out in this report.

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M8.2 - (Closed) VIO 50-263/98002-04(DRP): Failure to ensure that Surveillance Test 0149

- incorporated the requirements and acceptance limits contained in TSs. This violation is in the licensee's corrective action program as Condition Report 98000372, "WO used to -

perform Tech Spec Surveillances."

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This Severity Level IV violation was issued in a Notice of Violation prior to the March 11, 1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because this violation would have been treated as Non-Cited Violation in accordance with Appendix C, it is being closed out in this report.

M8'3 (Closed) Licensee Event Report (LER) 50-263/99-001. Revision 00: High Pressure

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Coolant injection (HPCI) High Steam Flow isolation During Quarterly Surveillance Test.

This event is discussed in Section O1.2 of Inspection Report 50-263/99001(DRP). ,

Appendix B, Criterion V, " Instructions, Procedures, and Drawings," of 10 CFR Part 50, requires in part that activities affecting quality be prescribed by documented procedures of a type ~ appropriate to the circumstances. Contrary to the above, Surveillance Test Procedure 0255-06-IA-1, Revision 40,"HPCI System Test with Reactor Pressure at Rated Conditions," performed on February 15,1999, did not ensure that a HPCI high steam flow isolation would be prevented. This Severity Level IV violation is being l treated as a Non-Cited Violation (NCV), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition Report 90000470, "HPCI Group IV lsolation During 0255 Surveillance Test."

(NCV 50-263/99002-02(DRP))

111. Enaineerina E1' Conduct of Engineering -

E1.1 Temoorary Modification to inhibit Reactor Protection System. Turbine Trio Scram.

Bvoass Function a. - Insoection Scooe (37551)

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The inspectors observed work and reviewed WO 9904607, ? Remove Fuses for TSV

[ turbine stop valve)/TCV [ turbine control valve] SCRAM Bypass Logic," associated

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Form 3034, Revision 17, " Jumper Bypass," and Form 3278, Revision 1, "10 CFR 50.59 Applicability Screening," associated with the isolation of the turbine first stage pressure input to the reactor protection system.

b. Observations and Findinas The reactor protection system turbine stop valve and turbine control valve fast closure scrams were bypassed at low power. The purpose of this trip was to prevent an

' unnecessary reactor trip if difficulties arose when the turbine was started or secured.

The signal which allowed bypassing of the scram was derived from turbine first stage pressure.

On March 17,1999, operators investigating a small steam leak near the main turbine discovered that root valves which isolated the pressure sensors for this turbine related scram bypass signal were leaking. An initial operability determination concluded that the leak could possibly impact the setpoint in the nonconservative direction. Safety and engineering evaluations were performed and the bypass function was subsequently inhibited by removal of the associated fuses. Procedural controls were instituted to re-establish the scram bypass during a reactor shutdown after reactor power was determined to be conservative with respect to the allowable setpoint.

Prior to the removal of the fuses to inhibi+. the scram bypass, the inspectors reviewed the temporary modification package, including the engineering evaluation and safety evaluations. The inspectors noted no safety significant discrepancies, but did note that one alarm window, which would be rendered inoperable by the temporary modification, l had not been flagged as inoperable. This was required to ensure that operators were i aware that the indication was unavailable. Subsequently, the inspectors reviewed j

'informat cn provided to the operators, including operations memorandum and jumper / bypass tags, and found that instrumentation affected by the modification had been identified and operators informed of component unavailability, j l

Inspectors observed the removal of fuses and noted proper peer checking, three-way I communications, engineering, and supervisory involvement. A pre-job briefing was conducted in the control room with all personnel involved. Procedures for the temporary modification were thorough and easily understood by operators performing associated tasks.

c. Conc lusions -

Engineering and safety evaluations for inhibiting the reactor protection system bypass function for the turbine stop valve closure and turbine control valve fast closure scram were comprehensive. No safety significant issues were identified. Engineering and supervisory involvement were observed throughout the evoluun

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IV, Plant Support l

R1 Radiological Protection and Chemistry Controls l R1.1 General Comments (71750)

During routine tours of the plant and observations of plant activities, the inspectors found that access doors to locked high radiation areas were properly secured, areas were properly posted, and personnel demonstrated proper radiological work practices.

The inspectors reviewed various survey data and RWP use and found that personnel were logged onto the correct RWP for the work being performed. Personnel logged into RWPs were wearing proper protective clothing and kept radiation protection personnel informed of activities as required by the RWP. Additionally, the inspectors found surveys to be timely and accurate.

R1.2 Technical Specification Reouired Discharoe Canal Grab Samole (71750)

On February 24, inspectors obsented chemistry technicians sample the discharge canal as required by TS 3.8.1 when the discharge canal sample pump was inoperable for maintenance. Chemistry technicians were knowledgeable of their assigned tasks which were performed in accordance with approved procedures.

S1 Conduct of Security and Safeguards Activities S1.1 General Comments (71750)

During this inspection period, the inspectors observed the licensee implement proper physical security measures associated with the integrity of protected area barriers, personnel and package access, personnel searches, and response to a lost badge.

F2 Status of Fire Protection Facilities and Equipment l

F2.1 General Comments (71750)

During normal resident inspection activities, routine observations were conducted in the area of fire protection. Fire extinguishers and fire hoses were properly stored and inspected by licensee personnel, No notable degradation of equipment was noted.

V. Manaaement Meetinos X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on April 8,1999. The licensee acknowledged the findings 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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n 4P PARTIAL LIST OF PERSONS CONTACTED Licensee

' B. Day, Plant Manager.

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M. Hammer, Site Manager M. Lechner,' Acting General Superintendent Operations L. Nolan, General Superintendent Safety Assessment E. Reilly, General Superintendent Maintenance LC. Schibonski, General Superintendent Engineering A. Ward, Manager Quality Services .

L. Wilkerson, Superintendent Security J. Windschill, General Superintendent, Radiation Services INSPECTION PROCEDURES USED

.lP 37551:_ Onsite Engineering .

'IP 61726: Surveillance Observations IP 62707: Maintenance Observations

,IP 71707: Plant Operations

. lP 71750: Plant Support Activities .

IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor

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IP 92902: Followup - Maintenance

' ITEMS OPENED AND CLOSED Opened .

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50-263/99002-01 'IFl . Concerns over adequacy of scaffolding controls .

50-263/99002-02- NCV - l HPCI Group IV isolation during 0255 surveillance test Closed L 50-263/98002-03 - VD . Failure to provide adequate instructions for lifting crates to the refueling floor

50-263/98002-04_. VIO Failure to ensure that surveillance test 0149 incorporated the requirements and acceptance limits contained in TSs

!50-263/99002-02 NCV . HPCI Group IV isolation during 0255 surveillance test

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50-263/99-001'

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LER. HPCI High Steam Flow isolation During Quarterly Surveillance Test

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LIST OF ACRONYMS USED AWI Administrative Work Instruction CFR Code of Federal Regulations CRD Control Rod Drive DRP Division of Reactor Projects HPCI- High Pressure Coolant injection IP inspection Procedure *

lbs pounds LER Licensee Event Report NCV Non-Cited Violation NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation NSP Northern States Power l PDR Public Document Room i RWP Radiation Work Permit l SPDS Safety Parameter Display System SRV Safety Relief Vaive STA Shift Technical Advisor SW - Service Water TCV Turbine Control Valve TS Technical Specification TSV Turbine Stop Valve URI Unresolved item {

USAR Updated Safety Analysis Report j

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VIO Violation WO Work Order

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