IR 05000263/1998011

Insp Rept 50-263/98-11 on 980528-0718.No Violations Noted. Major Areas Inspected:Licensee Operations,Engineering,Maint & Plant Support

ML20237E194
Person / Time
Site:	Monticello
Issue date:	08/21/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20237E192	List: IR 05000263/1998011 ML20237E190
References
50-263-98-1, 50-263-98-11, NUDOCS 9808310027
Download: ML20237E194 (21)

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION lli i

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Docket No: 50-263

- License No: DPR-22 Repcit No: 50-263/98011(DRP)

Licensee: Northem States Power Company

- Facility: Monticello Nuclear Generating Station Location: 2807 West Highway 75 Monticello, MN 55362 Dates: May 28 through July 18,1998 Inspectors: A. M. Stone, Senior Resident inspector D. Wrona, Resident inspector C. S. Thomas, Resident inspector, Prairie Island Approved by: M. Kunowski, Acting Chief Reactor Projects Branch 7

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9808310027 980821 i PDR ADOCK 05000263 l G PDR 3

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EXECUTIVE SUMMARY Monticello Nuclear Generating Station, Unit 1 NRC Inspection Report 50-263/98011(DRP)

This inspection included aspects of licensee oper&tions, engineering, maintenance, and plant support. The report covers a 7-week period of resident inspectio Operations

. Operational activities were generally performed in accordance with administrative procedures. Shift tumovers were acceptable and included detailed discussions of equipment status. Shift briefings were informative. (Section 01.1)

. Overall, operators were attentive to panels; however, two examples of inattention-to-details on panels were identified. Also, a plant operator did not follow a pump start procedure. which resulted in a safety-related pump operating 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> without motor cooling. Although the immediate safety significance of this event was minimal, operating safety-related equipment without requiring procedures in-hand was a poor practic _ (Section O1.1)

. Operations personnel did not anticipate that steam chase area temperatures would exceed procedural limits. This discrepancy was not identified during panel walkdowns since this parameter was recorded only once during the shift, early in the momin Operations personnel immediate corrective actions, which included increased monitoring and obtaining engineering personnel support, were acceptable. (Section 01.2)

. Operations personnel responded promptly and appropriately to a reactor power transient caused by thunderstorm-induced disturbances to the electrical distribution grid, in addition, during an unrelated condenser vacuum transient, operators quickly executed a reactor power reduction and appropriately stabilized the decreasing condenser vacuu However, shift management misread an abnormal procedure step and did not initiate a reactor scram required for turbine protection purposes. The licensee's initial assessment of operator performance during the condenser vacuum transient was critical and .

thorough. (Section 01.3)

. Changes to operations manuals were adequately controlled. Two minor examples of failure to follow administrative processes were identified. (Section O3.1)

. . Assessment activities by the line organization were event-driven or resulted from industry issues. Corrective actions for identified concems were timely and appropriate. No formal

. process existed to assess routine operations, which was considered a weakness in the assessment program. (Section 07.1)

Maintenance

. In general, the observed maintenance and surveillance activities were conducted in accordance with procedures and in a professional manner. Pre-job briefings were thorough and supervisory oversight was appropriate. No concems with the technical adequacy of surveillance testing were identified by the inspectors. (Section M1.1)

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. Engineering personnel provided excellent support to the maintenance staff during routine maintenance and surveillance. (Section M1.1)

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Report Details Summary of Plant Status The Unit operated at or near 100 percent power for most of the inspection period. On June 29, 1998, operators reduced power to 24 percent using recirculation pumps and emergency rod insertion procedures in response to an unexpected decrease of condenser vacuum. The Unit was retumed to 100 percent power later that day.

I 1. Operations

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j 01 Conduct of Operations I 0 General Observations of Operational Activities Inspection Scope (Inspection Procedure (IP) 71707)

The inspectors observed routine control room activities including shift tumovers, communications, control room access control, control board monitoring, and general control roem decorum. Documents reviewed as part of this inspection included:

. Updated Safety Analysis Report (USAR) Section 13, " Plant Operations,"

. Administrative Work Instruction (4AWI) 04.01.01, Revision 19, " General Plant Operating Activities,"

. Operational Work Instruction (OWI) 01.01, Revision 1, " Operations Group Organization and Responsibility Assignments,"

. OWI-01.02, Revision 1, " Operations Policies,"

. owl-01.03, Revision 2, " Operations Communication Standard,"

. owl-01.04, Revision 1, " Operations General Procedural Guidance,"

. owl-01.06, Revision 1, " Duty Operations Personnel Requirements and Responsibilities,"

. OWi-02.01, Revision 1, " Operation Shift Tumovers,"

. owl-02.03, Revision 2, " Operator Rounds," and

. Procedure 1440, Revision 1, "NRC Ucense Active Status Maintenance.'

' Observations and Findinos

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l The conduct of routine operations was acceptable. Work activities were performed in a professional and controlled manner. Operations personnel were knowledgeable of r equipment status and of on-going activities with one exception, as noted in Section 01.2.

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Specific observations of routine activities included:

. Administrative Procedure 4AWI 04.01.01 stated that upon entering the control room, a duty control room operator should be informed of the nature of business and that permission must be obtained prior to entering the operating area marked by the lighter colored carpet. Yhe inspectors noted that on numerous occasions, plant personnel entered the concol room without stating their business and !

entered the light-colored carpeteo 9rea without first obtaining permission from the i

control room operators. On two occasions, the inspectors observed plant personnel enter the light-colored carp ited area while wearing hardhats. This practice, while not prohibited by the prt. :edure, was poor. The L;pectors described these observations to the supt.rintendent of operations, who immediately communicated the expectations descrioed in the administrative procedure to other department managers.

L l . Tumovers were conducted in accordance with procedures and management's expectations. The inspectors observed off-going and on-coming operators perform walkdowns of front and back panels prior to taking shift. Operators discussed equipment status, on-going maintenance, and previous operational evolutions in detail. For example, an off-going operator clearly described a 1R transformer degraded voltage condition to an on-coming operator. Panel i walkdowns by on-coming shift management were not always conducted prior to taking shift, but if they were not, they were accomplished immediately after the start of the shift. The inspectors noted that OWI 02.01 did not require operations

' personnel to walkdown the control room panels or review the log entries with their counterparts prior to assuming shift duty and concluded that management expectations in this area were lo . Shift briefings were effective in ensuring teamwork and coordination of activities between operations and other departments. Shift supervisors discussed , ,

maintenance and surveillance activities planned for the shift and presented an !

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l opportunity for others to add information to the briefin A ses ma W in the control room operator's log-book were timeiy and accurately

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- reflected on-going activities and occurrence i

. The inspectors reviewed Procedure 1440 covering the first quarter of 1998 and verified that operations support personnel had performed the necessary licensed duties to maintain an active license in accordance with 10 CFR 55.53(e).

. The inspectors accompanied plant operators during rounds in the reactor building

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and turbine building. The plant operators demonstrated knowledge of current

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plant status and addressed identified housekeeping issues such as minor oil leaks The inspectors noted that plant operators documented some plant parameters on scrap pieces of paper to transfer to the official Technical Specification (TS)-required surveillance test later. While no instances of incorrect transfer of information were identified, the inspectors were concemed that this practice could lead to errors.

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. Operators were generally attentive to the control board panels with the most attention appropriately focussed on the center panel. Control room panel walkdowns were conducted about once every two hours when operators documented selected parameters on their round sheets. The inspectors noted that operating procedures and policies did not include management expectNions on the frequency of panel walkdowns. This is considered a weakness because

, the inspectors have identified discrepancies on the panels which should have been identified by the operators as documented in inspection Reports 50-263/98002 and 50-263/98004. As discussed in Section 01.2 of this report; the inspectors identified that steam chase temperature exceeded the value .

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specified on the operator round sheets. Also, a placard on the standby gas treatment panel stated that painting was in progress; however, a note written on the shift supervisor's white board reported that no painting in the reactor building was allowed. While these examples did not result in equipment inoperabilities, the inspectors remained concemed with panel awarenes . Operators appropriately referenced annunciator procedures when unexpected alarms were received. However, operators did not always announce control room alarms to other crew members in accordance with the expectations delineated in owl-01.0 . Control room operators adhered to surveillance test procedures and consistently l

used three-way, repeat-back communication techniques. Control of activities was appropriate. For example, an operator, distracted by maintenance and engineering personnel discussing rod worth minimizer troubleshooting activities, requested that the conversation be held outside of the control room. Plant

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operator performance during surveillance testing was acceptable. However, on .

June 17,1998, a plant operator was requested to start the #12 residual heat

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removal service water (RHRSW) pump in accordance with Operations Manual B.8.01.3-05.D.1, "Startup of RHRSW Pump " to support post-maintenance testin About 2M hours later, the system engineer noted that the motor cooling was not valved in and questioned operators who confirmed that cooling water had not been lined up prior to the pump start. Step 2 of Procedure B.08.01.03-05 required the operator to open Valve RHRSW-21-2 prior to starting the pum Step 4.1.3 of Procedure OWi-01.04 did not require operators to have procedures

"in-hand" during all evolutions, but did require operators to ensure procedure adherence when performing non-routine activities in procedures such as startup/ shutdown or B-manual procedures by reading the apphcable procedures L prior to performance, during performance, or after performance of tne activity. The operator had not read the procedure but had intended to verify his actions -

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afterwards. However, the operator was immediately assigned other tasks and I

failed to perform the post-implementation review. The pump was inoperable at the time; therefore, failing to valve in cooling water did not impact operability. The failure to follow procedure constitutes a violation of minor significance and is not subject to formal enforcement action. Although the immediate safety significance of this event was minimal, operating safety-related equipment without requiring procedures in-hand was a poor practic !

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. Conclusions Operational activities were generally performed in accordance with administrative procedures. Shift tumovers were acceptable and included detailed discussions of equipment status. Shift briefing were informative. Overall, operators were attentive to panels; however, two examples of inattention-to-details on panels were identified. Also, a plant operator did not follow a pump start procedure, which resulted in a safety-related pump operating 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> without motor cooling. Although the immediate safety significance of this event was minimal, operating safety-related equipment without

. requiring procedures in-hana was a poor practic .2 Elevated Steam Chase Temperatures Not Anticipated

. Inspection Scope UP 71707)

On July 9,1998, the inspectors identified that some steam chase area temperatures had (

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exceeded 135 degrees Fahrenheit (*F) and were outside of acceptance criteria specified in the operators' daily log sheet. The inspectors assessed the licensee's follow up to this issue and reviewed the following documents:

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. Annunciator Response Procedure (ARP) 5-A-18, Revision 1, %eam Tunnel Hi l Temperature Channel B,"

. ARP 3-B-56,"High Area Temperature Steam Leak,"

. Condition report (CR) 98001727, " Steam Chase Temperature Excursions above 135'F," and

. Surveillance Test 1325, Revision 68, " Steam Chase Temperature Check."

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! Observations and Findinas Operators recorded steam chase temperatures once per 12-hour shift in accordance with Surveillance Test 1325. This was done to verify that steam chase area temperatures were maintained below 135 'F. The inspectors noted that the operators recorded the temperature earty in the moming shift and no subsequent monitoring was done, in mid-( aftemoon of July 9,1998, the inspectors observed that the area temperature near the l outboard B main steam isolation valve (MSIV) was 136*F and notified the shift manager.

!- The shift manager immediately contacted the environmental qualification (EQ) engineer and increased the monitoring from once per day to every 15 minutes until average area temperatures were consistently below 135'F. A temporary procedure change was written to define expectations for monitoring and to require a potential reactor power reduction if l sustained high temperatures were noted. The EQ engineer determined that the 135'F

!' limit was used in determining the qualified life of the MSIV solenoid valves and other EQ

[ equipment in the room. The engineer stated that temporary excursions above 135'F t would not affect the EQ rating for the equipment; therefore, the equipment in the steam chase area remained operable. The inspectors had the following concems:

. Although operations personnel were aware of the higher temperatures in the general areas, extra monitoring of the steam chase area was not initiated. This is

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of concern since operations personnel did not know the bases for the 135 F limit contained in Surveillance Test 132 .

Further investigation showed that the high energy line break analysis of record assumed an initial steam chase area temperature of 140 F. The inspectors noted that the high area temperature annunciator would be received at 165'F and was used to identify potential steam leaks in the steam chase. Therefore, the current setpoints could have allowed operation with temperatures above those assumed in the high energy line break analysis. The licensee believed that steam chase average area temperatures may have exceeded 140*F during previous maintenance and surveillance activitie These concems are considered an Inspection Followup Item (IFl 50-263/98011-01(DRP))

pending review of the licensee's corrective action Conclusions Operations personnel did not anticipate that steam chase area temperatures would exceed procedural limits. This discrepancy was not identified during panel walkdowns since this parameter was recorded once during the shift, early in the moming. Operations personnel immediate corrective actions, which included increased monitoring and obtaining engineering personnel support, were acceptabl .3 Operator Response to Non-routine Events Inspection Scope (IP 71707)

The inspectors assessed operator performance during two non-routine events which occurred during this perio Observations and Findinos Operators responded to a reactor power transient caused by an electrical storm and to a condenser vacuum transient resulting from equipment failure. The inspectors were not onsite during the events and assessed operator performance through the review of control room log entries, annunciator alarm printouts, graphs of selected parameters, and app!icable abnormal procedures and through discussion with operations personnel. The following ohrvations were made:

. In the evening of June 25,1998, severe thunderstorms caused significant electrical grid disturbances which resulted in an increase in recirculation pump speed and subsequent increase in total core flow. Control room operators observed generator output fluctuations between 562 and 576 megawatts-electric (MWe). The operators reduced recirculation flow to maintain reactor power below 100 percent. Through review of instrument parameter graphs, control room log book, and annunciator alarm prints, the inspectors confirmed that the operators responded appropriately to the event. Engineering personnel determined that reactor power exceeded the 100 percent licensed rated thermal power of l 1670 megawatts-thermal (MWt) for about 4 minutes during the transient. The maximum power was estimated at 1685 MWt which is less than 101 percent rated

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e thermal power. The inspectors agreed that this event was not reportable since reactor power had not exceeded 102 percent and the time that power exceeded 100 percent was short. This is consistent with a current regulatory position as described in an August 22,1980, NRC memorandum from E. Jordan to j E. Brunnar.

l . On June 29,1998, the #12 recombiner condensate pump tripped because of a bearing problem and the #11 pump did not automatically start as expected because of a faulted time delay relay. As a result of these equipment failures,

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condenser vacuum dropped quickly and dipped below 24 inches mercury (24" Hg)

before operators were able to recover vacuum by opening the mechanical vacuum l- pump suction valves. Operators entered Abnormal Procedures C.4-B.6.3.A,

[ " Decreasing Condenser Vacuum," and C.4.F " Rapid Power Reduction,"

concurrently. Per Procedure C.4.F. operators decreased recirculation flow and

began inserting control rods. Reactor power was reduced to about 24 percen Condenser vacuum stabilized at around 24" Hg for about 18 minutes then --

increased as a result of operator actions in accordance with

Procedure C.4-B.6.3.A. Ascension to 100 percent power resumed after the equipment failures were correcte As discussed in Section 07.1, the plant manager requested operations personnel

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to review operator actions during this event. The investigation showed that generator power was less than 170 MWe when condenser vacuum was below

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25" Hg for an 8-minute period. Step 3 of Abnormal Procedure C.4-B.6.3.A. stated

that IF condenser vacuum was less than 25" Hg AND turbine load was less than 170 MWe OR condenser vacuum could not be recovered, the operators were

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required to reduce recirculation flow to minimum and manually scram the reacto The shift manager and shift supervisor failed to initiate a reactor scram in accordance with Procedure C.4-B.6.3.A. The inspectors interviewed the shift supervisor and lead operator and determined that the IF-AND-OR conditional statement was misread. Shift management believed that since condenser vacuum was stabilized and increasing (and to preclude another transient), a j reactor scram was not required. The purpose of the scram under this power and condenser vacuum condition was to prevent damage to the last stage turbine blades. The licensee was evaluating the need for this scram and considering further procedural guidance for the operator l

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The failure to follow Abnormal Procedure C.4-B.6.3.A is contrary to Technical Specification 6.5.A.1 which requires the licensee to follow integrated operating .

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procedures. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-263/98011-02(DRP)).

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c. . Conclusion Operations personnel responded promptly and appropriately to the reactor power l- transient caused by thunderstorm-induced disturbances to the electrical distribution grid.

L in addition, during an unrelated condenser vacuum transient, operators quickly executed l a reactor power reduction and appropriately stabilized the decreasing condenser vacuu However, shift management misread an abnormal procedure step and did not initiate a

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reactor scram required for turbine protection purposes. The licensee's initial assessment of operator performance during the condenser vacuum transient was critical and thoroug Operations Procedures and Documentation l

O3.1 Temporary chances to Operations Manual Procedures Inspection Scope (IP 71707)

The inspectors reviewed several outstanding operations manual temporary procedure changes (referred to as " Volume Fs") to ascertain operator knowledge of and administrative control of the temporary changes. The following documents were reviewed: i

. 4 awl-02.02.06, Revision 4, " Volume F Memorandums,"

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l . Volume F #1689, " Operation of Pressure Control Station in Attemate Nitrogen l System," dated May 1,1998,

. Operations Manual B-8.4.3-05, Revision 2, "Altemate Nitrogen System - System Operation,"

. Volume F #1703, "ARP 6-A-28 [ condensate pump motor high bearing

' temperature] Setpoint Change and Action Level Change," dated June 24,1998, and

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. CR 98001634, "A review of active Vol. F memos raises questions regarding !

implementation of 4AWI 02.02.06." Observations and Findinos l All active Volume Fs were maintained in a notebook located in the control room. The inspectors verified that operators were aware of the changes and that the corresponding operations manual procedures were annotated with the Volume F change. The following -

concems were identified by the inspectors:

l . Volume F #1696 involved the addition of eight sub-procedures to Operations Manual B-8.4.3-05. These included instructions to adjust pressure control valves and pressure regulating valves and transfer between these valves during system pressure changes.. Step 4.1.2 of 4 awl-02.02.06 stated that Volume F memos shall not change the scope or intent of an approved procedure. Step 4.1.8 stated that Volume F memos shall not authorize physical removal or addition of pages to l the operations manual. The inspectors determined that the addition of these sub-procedures was contrary to the guidance provided in 4AWi-02.02.0 l

. Volume F #1703 revised the annunciator procedure for the condensate bearing temperature alarm to reflect a new setpoint. The inspectors noted that the setpoint change was in progress under Work Order 9802382 which had not been completed prior to the authorization of the annunciator procedure revision. The

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control room operators were aware that, although the Volume F was authorized, it was not effective until this setpoint change was completed. The authorization of f- the Volume F prior to the setpoint change was not in accordance with 4 awl-02.02.06; The inspectors discussed these observations with members of the operations staff and superintendent of operations. The licensee initiated CR 98001634 to address these concems. The significance of these administrative errors was minor; therefore, the failure to follow 4AWI 02.02.06 is not subject to formal enforcement action.

! Conclusions Changes to operations manuals were adequately controlled. Two minor examples of failure to follow administrative processes were identifie Quality Assurance in Operations (.

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. 0 Departmental Assessment Activities

Inspection Scope (IP 71707) The inspectors evaluated the assessment process within the operations departmen Several condition reporth were reviewed including the following:

- .- CR 98001566, "12 RHRSW run without motor cooling,"

i i CR 98000137, " Licensed Operator Requalification NRC Inspection at Prairie

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! * CR 98001649, " Rapid Power Reduction due to a Failure of the Standby Recombiner Coolant Pump P902A to Auto Start."

t Observations and Findinas

The inspectors identified that assessments performed within the operations department L were initiated during followup of events or resulted from industry issues. However, the

inspectors noted that the assessment activities did not identify concems with the conduct i

of routine operations such as panel attentiveness and attention-to-detail issues discussed in Section 01.1. The likely cause of this was the lack of a formal process to assess

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routine operations. Assessments performed by General Quality Services (quality I assurance) personnelincluded observations of non-routine activities such as startups and shutdowns. '

i For events involving potential personnel error, operator performance was evaluated

- during the assessment phase of the condition reporting process. Corrective actions to address cause and contributing factors were timely and appropriate. As an example, the licensee initiated CR 98001566 when a system engineer identified that the #12 RHRSW had been operating without motor cooling, contrary to operational procedures. The licensee's initial evaluation concluded that the plant operator involved was overloaded with otherJob tasks and forgot to verify proper alignment of motor cooling valves. The

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licensee planned to discuss this event including expectations on procedure adherence and prioritization of work, with the appropriate work group The inspectors also noted that station management requested assessments of operator perfomiance after significant events such as near-miss scrams and shutdown and startup activities. These assessments were generally self-critical and resulted in several  ;

procedural enhancements and policy changes. For example, the plant manager  ;

requested that operations personnel evaluate operator performance during the condenser !

. vacuum transient documente ! in CR 98001649. The investigation showed that operators ;

failed to initiate a reactor scram in accordance with abnormal procedures when generator '

power was less than 170 MWe and condenser vacuum was below 25 inches. Shift management misread the abnormal procedure and believed that since vacuum was improving, a scram was not required. The licensee's investigation had not been completed at the end of this inspection period; however, the superintendent of operations immediately discussed the event with all operations crews and reemphasized procedural adherence and questioning attitude expectations, issues identified through generic communications such as NRC Information Notices or identified at other facilities were entered into the condition reporting process and evaluated for applicability. For example, the licensee reviewed Prairie Island Inspection Report 50-282/97019(DRS); 50-306/97019(DRS) and determined that several weaknesses discussed in the report also existed at Monticello. The licensee identified l three operations policies which should be included in operations committee-approved

' procedures. Administrative work instructions and operations work instructions were revised accordingly, Conclusions Assessment activities by the line organization were event-driven or resulted from industry issues. Corrective actions foridentified concems were timely and appropriate. No formal process existed to assess routine operations, which was considered a weakness in the assessment progra ' 08 Miscellaneous Operations issues

.0 (Closed) inspection Followup Item (IFli 50-263/98004-01(DRP): Surveillance requirement with no corresponding limiting condition for operation (LCO).

Each month, TS 4.9.B.3.b requires the licensee to verify the capability of the emergency diesel generator (EDG) starting air compressors (SACS) to recharge the air tank However, the operability requirements of the SACS are not explicitly described in TS

Section 3.9.B.3. Therefore, it was not clear what actions the licensee was required to

take if the surveillance test described in TS 4.9.B.3.b was missed or if the acceptance L criterion was not met. After further discussion with Office of Nuclear Reactor Regulation I

personnel, the inspectors concluded that the licensee's action of entering an administrative LCO was acceptable since the TS did not explicitly state that the EDGs need to be declared inoperable because of an inoperable SAC. The safety significance of j

. this issue is minor and does not warrant a TS change to require EDG inoperabilit Standard TSs do not include SAC testing. The licensee planned to convert to improved Standard TSs in the near future and this ambiguity will be addressed the _ - - - _ _ _ _ _ _ .

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08.2 (Closed) IFl 50-263/97014-02 (DRPl: Technical Specification change request required to change existing non-conservative setpoin On November 25,1997, the licensee submitted a TS amendment request to revise the condensate storage tank level setpoint for reactor core isolation cooling (RCIC) and high pressure coolant injection (HPCI) suction valve realignment. Instrument calibration and routine surveillance tests were revised to include the new setpoint '

08.3' (Closed) Licensee Event Report (LER) 50-263/97-011: Errorin Procedure Causes Failure to Transfer the HPCI and RCIC Suetions to the Suppression Pool After Making a Condensate Storage Tank Level Instrument inoperable. This event was discussed in Inspection Report 50-263/97014 and was considered a non-cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Polic .4 (Closed) Violation (VIO) 50-263/97006-01(DRP): Operations personnel were unaware that ;

the #13 emergency service water pump had been operating for 46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br />.

l As documented in _ Inspection Reports 50-263/97003 and 50-263/97006, the pump l automatically started when a loss of power to the #15 essential electrical bus occurred.

L The abnormal procedure used to restore equipment did not include steps to secure the

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emergency service water pumps. Operators did not identify that the pump was operating during routine panel walkdowns and four shift tumovers involving three crews. The l licensee corrective actions included reviewing the event with operations personnel, l developing training expectations, and revising the restoration procedure. Although

! concems with attention-to-detail to control roon panels still exist as discussed in Section O1.2, improvements with the quality of shift tumovers were noted. In addition, the inspectors observed that shift management often assigned additional operators to l~ perform independent panel walkdowns during subsequent non-routine events such as a loss of condenser vacuum condition in November 199 II. Maintenance M1 Conduct of Maintenance

, . M1.1 ~ General Comments on Observed Maintenance and Surveillance Testina Activities a. ~ Inspection Scope (IPs 62703 and 61726)

The inspectors observed all or portions of selected maintenance and surveillance activities.' included in the inspection was a review of the surveillance procedures or work orders listed as well as the appropriate USAR sections pertaining to activitie Observations and Findinas in general, the inspectors observed that the work associated with these activities was conducted in a professional and thorough manner. All work observed was performed with t

the work package present and in active use. Technicians were experienced and

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knowledgeable of their assigned tasks. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were

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l f present whenever required by procedure. When applicable, appropriate radiation control l l measures were in place.

i The following work was observed. Specific concems or observations are provided where appropriat . Work Order 9802309, " Investigate HPCI Discharge Line Response." This work was part of an on-going investigation into the cause of water hammers in the

. HPCI syste . Surveillance Test 0030, Revision 7, "ECCS (emergency core cooling system) High

! Drywell Pressure Sensor."

Excellent three-way, repeat-back communications between the operators and instrument and control technician was noted. The inspectors verified that the stated acceptance criteria was consistent with TS Table 3.2.2 and USAR

Table 7.6-1 value . Surveillance Test 0081, Revision 28, " Control Rod Drive Scram insertion Time Test."

. Surveillance Test 0085, Revision 25, "SBLC (Standby Liquid Control] System Operability Test."

. Surveillance Test 0143, Revision 25, "Drywell-Torus Monthly Vacuum Breaker Check and Instrument Air System Valve Exercise."

. Surveillance Test 0255-03-IA-1, Revision 25, " Core Spray System Tests."

. Surveillance Test 0266, Revision 34, " Fire Pumps Simulated Auto-Action and i Capability Test."

The inspectors verified that the acceptance criteria specified in Surveillance Test 0266 were consistent with TSs 3.13 and 4.13. The system engineer provided excellent oversight during the performance of the test. Minor concems were brought to the attention of the system engineer and were promptly addresse . Surveillance Test 0278b, Revision 7, "ATWS (anticipated transient without a scram) - Recire Trip for Reactor Pressure and Level Trip Unit Test and Calibration."

Communications between the instrument and control technician and the control room operator were clear. The test was conducted in a controlled and deliberate manner. A minor procedural adherence concem was addressed promptly. The inspectors also verified the "as found" and "as left" trip values were consistent with TS 3.2 and USAR Section 7. . Surveillance Test 1054, Revision 6," Control Rod Drive Normal Drive Timing Test."

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I Conclusions in general, the observed maintenance and surveillance activities were conducted in accordance with procedures and in a professional manner. Pre-job briefings were

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thorough and supervisory oversight was appropriate. Engineering personnel provided excellent support to the maintenance staff. No concems with the technical adequacy of surveillance testing were identified by the inspector I M8 Miscellaneous Maintenance issues i M8.1 (Closed) VIO 50-263/97006-01(DRP): Three examples of failure to follow procedure Two examples involved the failure to follow the equipment tagging procedure. The licensee discussed the events with maintenance and operations personnel and did not -

identify any concems with respect to equipment tagging during the subsequent refueling )

outage or on-line maintenance activities. The third example involved inaccurate  !

information contained on several RCIC electrical drawings. The licensee determined that i redundant information was provided on multiple drawings; however, updates were not always performed on all applicable drawings. The licensee's corrective actions included discussing the event with engineering personnel and continuing their as-built verification effort Ill. Enaineerina E8 Miscellaneous Engineering issues E8.1 - (Closed) IFl 50-263/97018-05(DRP): Incorrect description of the automatic depressurization system (ADS) in the USA The inspectors identified that the USAR incorrectly described the ADS initiation logic as a one-out-of-two-twice logic circuit. Operations personnel immediately assessed operability and concluded that based on the description in the TS bases, ADS was operable. The licensee initiated CR 97003216, "USAR Section 6.2.5.2 and control prints for ADS logic appear to be inconsistent," and also identified other errors. ' The licensee concluded that =

the as-built plant condition was in accordance with design basis and the description in the USAR was incorrect. Engineering personnel completed a 10 CFR 50.59 safety evaluation l and concluded that a wording change in the USAR did not constitute a unreviewed safety j

-. question. The licensee intended to submit the USAR change accordingl j E8.2 - (Closed) IFl 50-263/97015-03(DRP): Operability of the RHRSW pumps with degraded )

motor cooling flow and river temperatures above 53 * In October 1997, operators noted decreased cooling water flow to the RHRSW pump ' Engineering personnel concluded that the pumps were operable based on achieved flow  !

rates assuming a river temperature less than 53 'F and documented their results in l CR 97002676, " Low Flow on #11 and #13 RHRSW Motor Coolers." During the 1998  !

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refueling outage, the licensee completed modifications to address the issue. The modifications included rerouting and replacing piping; increasing relief valve and pressure control valve setpoints; and installing new valves to facilitate future cleaning effort _

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Engineering personnel contacted the vendor to clarify motor cooling flow requirements specified on equipment drawings. The measured motor cooling flow rate for each pump

. was acceptable; therefore, the restriction on operating above 53 'F river temperature was remove ~ E8.3 (Ocen) IFl 50-263/97006-04 (DRP): Questionable dependence of the 1R transformer to the #10 transforme .

On June 24,1998, operators declared the 1R transformer inoperable due to low system voltage. The #10 transformer was out-of-service at the time of this occurrence. The low voltage condition was not expected since a modification implemented during the refueling outage should have eliminated the dependence between the 1R and #10 transformer The licensee later determined that another 115-kilovolt line in the grid was also inoperable which affected voltage at Monticello. Engineering personnel planned to use information gained from this event to verify the accuracy of the model used for the modification. This item remains open pending this verificatio E8.4 (Closed) VIO 50-263/97002-06(DRP): Failure to take timely corrective actions in revising a TS-required surveillance procedur In 1993, the licensee performed a calculation to determine the setpoints for the scram discharge volume level instruments. During that review, the licensee determined that the ,

acceptance criteria in Surveillance Test 0006, " Scram Discharge Volume Hi Level Scram '

Test," was incorrect; however, the revision was not made until the inspectors identified a related issue in 1997. The inspectors were also concemed that the calculation of record was not referenced in the surveillance test and that the acceptance criteria were technically inadaquate. Additional examples of surveillance test technical adequacy concems were documented in Inspection Report 50-263/96009. To address the specific concem of this violation, the licensee revised Surveillance Test 0006 and included a step -

in the appropriate Administrative work instruction to require formal tracking of open issues such as surveillance test revisions. A long-term corrective action included a commitment

- to review all TS-required surveillance for proper acceptance criteria and technical references. The licensee planned to complete this effort in March 2000. This long-term corrective action will be reviewed with Violation 50-263/96009-12(DRS).

- F_8.5 ' (Closed) IFl (50-263/96007-04(DRP): Completion of modification to resolve discrepancies with the reactor water cleanup high energy line break assumption As discussed in Inspection Report 50-263/98007, the inspectors observed some portions of the installation of this modification, and as documented in inspection Report 50-263/98009, regional inspectors reviewed the modification package and post-modification testing. No significant problems were identified by the inspectors. The licensee identified the necessary USAR changes which will be submitted to the NRC as ,

scheduled. No further action is needed with respect to this ite ]

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IV. Plant Support R1 Conduct of Radiological Protection and Chemistry Controls (IP 71750)

During normal resident inspection activities, routine observations were conducted in the area of radiation protection. The inspectors noted that radiation protection personnel provided excellent support to maintenance, engineering, and operations personnel during routine activitie S1 Conduct of Security and Safeguards Activities (IP 71750)

During normal resident inspection activities, routine observations were conducted in the areas of security and safeguards activities. The inspectors toured the protected area boundaries and also observed good security personnel support to maintenance activitie V. Manaaement Meetinas I

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X1 Exit Meeting Summary On July 20,1998, the inspectors presented the inspection results to members of licensee management. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietar No proprietary information was identifie j

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. PARTIAL LIST OF PERSONS CONTACTED Licensee i

M. Wadley, President Nuclear Generation j l-

• M. Hammer, Plant Manage ;)

• B. Day, General Superintendent Operations

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K. Jepson, Superintendent, Chemistry & Environmental Protection ,

L. Nolan, General Superintendent Safety Assessment l l *E. Reilly, General Superintendent Maintenance j l . C. Schibonski, General Superintendent Engineering i L *A. Ward, Manager Quality Services L. Wilkerson, Superintendent Security J. Windschill, General Superintendent, Radiation Protection

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• Indicates those present during an exit meeting conducted on July 20,199 l

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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering-IP 617.*6: Surveillance Observation IP 62703: Maintenance Observations

{ IP 71707: Plant Operatione IP 71750: Plant Support -

ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-263/98011-01(DRP) IFl Operators did not anticipate increased steam chase area temperatures and potential operation outside licensing basi /98011-02(DRP) ' NCV Failure to follow an abnormal operating procedure during a

. condenser vacuum transien ' _ _Qo_ged 50-263/98004-01(DRP) IFl- Surveillance requirement with no corresponding LC /97018-05(DRP) IFl incorrect description of ADS logic in the USA : 50-263/97015-03(DRP)

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IFl Operability of the RHRSW pumps with degraded motor cooling flow and river temperatures above 53 'F.-

50-263/97014-02 (DRP) ; _IFl Technical Specification change request required to change '

existing non-conservative setpoin /97-011 (DRP) LER Error in Procedure Causes Failure to Transfer the HPCI'

and RCIC Suctions to the Suppression Pool After Making a Condensate Storage Tank Level Instrument inoperabl /97008-01(DRP) VIO Three examples of failure to follow procedure /97006-01(DRP)' VIO Operations personnel were unaware that the #13 emergency service water pump had been operating for : 1 46 hour5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> /97002-06(DRP) VIO Failure to take timely corrective actions in revising a TS-required surveillance procedur ! 50-263/96007-04(DRP) IFl Completion of modification to resolve discrepancies with the reactor water cleanup high energy line break b assumptions, i I

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Discussed

50-263/97006-04 (DRP) IFl " stion ble dependence of the 1R transformer to the

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LIST OF ACRONYMS USED ADS Automatic Depressurization System ARP Annunciator Response Procedure ATWS Anticipated Transient Without Scram 4AWI Administrative Work Instruction CFR Code of Federal Regulations CR Condition Report

'F Degrees Fahrenheit DRP Division of Reactor Projects DRS Division of Reactor Safety ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EQ Environmental Qualification HPCI High Pressure Coolant injection

" Hg Inches Mercury IFl Inspection Followup Item IP Inspection Procedure IR Inspection Report LCO Limiting Condition for Operation LER Licensee Event Report MSIV Main Steam Isolation Valve MWe Megawatt Electric MWt Megawatt Thermal OWI Operations Work Instruction PDR Public Document Room RCIC Reactor Core Isolation Cooling RHRSW Residual Heat Removal Service Water SAC Starting Air Compressor SBLC Standby Liquid Control TS Technical Specification USAR Updated Safety Analysis Report VIO Violation WO Work Order

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