IR 05000263/1998004

Insp Rept 50-263/98-04 on 980224-0414.No Violations Noted. Major Areas Inspected:Operations,Engineering,Maintenance & Plant Support

ML20216C535
Person / Time
Site:	Monticello
Issue date:	05/08/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20216C524	List: IR 05000263/1998004 ML20216C521
References
50-263-98-04, 50-263-98-4, NUDOCS 9805190303
Download: ML20216C535 (28)

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U.S. NUCLEAR REGULATORY COMMISSION REGION lll Docket No: 50-263 License No: DPR-22 Peport No: 50-263/98004(DRP)

Licenseo: Northern States Power Company Facility: Monticello Nuclear Generating Station Location: 2807 West Highway 75 Monticello, MN 55362 Dates: February 24 through April 14,1998 Inspectors: A. M. Stone, Senior Resident inspector ,

D. Wrona, Resident inspector i S. Ray, Senior Resident inspector, Prairie Island Approved by: J. W. McCormick-Barger, Chief Reactor Projects Branch 7

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9805190303 90050s PDR G ADOCK 05000263 pg l

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I EXECUTIVE SUMMARY l

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Monticello Nuclear Generating Station, Unit 1 ]

l NRC Inspection Report No. 50-263/98004(DRP)

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

. Operator performance was acceptable. Improvements were noted in the tumover process and communications. No discrepancies were identified during review of isolation tags on equipment. In general, pre-job and infrequent evolution briefings were detaile However, the inspectors identified two examples of inattention-to-detail by reactor operators during control room panel walkdowns. (Section 01.1)

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The licensee conservatively applied shutdown risk concepts during the planning and execution of the 1998 refueling outage implementation of the outage plan was being conducted effectively and in a controlled manner. (Section O1.2)

i . Pre-outage activities were beneficial to the coordination and execution of outage work.

l The workload for operations personnel during the power reduction and first days of the

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outage was managed effectively as a result of pre-outage isolation and vessel disassembly meetings. The shutdown training provided to the operators was effective, in that several discrepancies with the shutdown procedure and other scheduled activities were identified and resolved prior to the actual shutdown. (Section 01.3)

. Operations personnel conducted the shutdown in a well-coordinated, controlled manner and in accordance with procedures. (Section O1.4)

. Refueling operations, which included about 850 separate fuel or core component moves, were conducted in a careful, deliberate, and error-free manner. (Section 01.5)

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. Engineering personnel provided excellent support to the maintenance staff. A weakness in the modification and jumper / bypass program interface was identified. (Section M1.1)

. The backlog of orrective maintenance work orders was relatively small and stabl Priority work and control room deficiencies received appropriate management and engineering staff attention. Equipment failures which led to Technical Specification limiting-conditions-for-operation were infrequent and rapidly resolved. Work was performed in a timely manner and was generally completed correctly the first tim Overall, a review of the maintenance backlog indicated a strong, well-implemented maintenance program. (Section M2.1)

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The root cause of the February 16,1998, minor water hammer in the high pressure coolant injection piping was not aggressively pursued by engineering personnel until questioned by the inspectors. The subsequent evaluation and corrective actions were appropriate. (Section E1.1)

Plant Support

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Radiation protection personnel provided excellent support to maintenance, engineering, and operations personnel during the refueling outage. Radiation protection technicians discussed radiation fields and contamination levels during pre-job briefings and at the drywell personnel access point. The technicians monitored job-sites and provided guidance to the workers. Excellent planning and execution of the removal of highly radiated reactor water cleanup piping were noted. (Section R1)

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Report Details Summary of Plant Status l

The Unit operated in a coast-down condition until March 20,1998, when operato l inserted a manual scram to commence the Cycle 19 refueling outage. The Unit was in cold shutdown for the remainder of the inspection perio l. Operations I 01 Conduct of Operations 0 General Performance Comments InsDeCtion ScoDe Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operation Observations and Findinas in general, the conduct of operations was acceptable. The inspectors made the following -

observations of routine and outage-related activities' -

. Individual operator and shift supervision tumovers improved. The inspectors observed panel walkdowns and detailed discussions on equipment status .

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between the off-going and on-coming crew . Operators were generally attentive to the control board panels with the most attention appropriately focussed on the center panel. The inspectors noted that on one occasion, a control room operator did not know why the #12 standby liquid control pump was operating. Other operators in the control room stated that maintenance personnel were adjusting the relief valve settings and needed the pump to be operatin Also, on a routine basis, operators documented selected equipment parameters o,i the control room log sheet during panel walkdowns. Though generally thorough, on two occasions, operators were unaware that some parameters were outside of the indicated maximum and minimum values specified in the log shee For example, on March 12,1998, the core spray (CS) piping pressure was less than the lower limit of 30 pounds-per-square-inch-gauge (psig) for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> before an operator noticed. Operations Manual B.3.1-05.A.4.a, " Core Spray Cooling System - System Operation," Revision 9, required CS piping pressure to be greater than or equal to 30 psig in order for the system to be considered operabl The licensee entered the appropriate limiting condition for operation (LCO) and resolved the problem. Also, on March 16,1998, the inspectors identified that for about three days, the reactor core isolation cooling steam pressure was at 1025 psig; however, the maximum value specified on the log sheet was 1020 psig. When questioned by the inspectors, the control room operator notified

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the system engineer who confirmed system operability. While individually these examples were not significant, they demonstrated that additional management attention in the area of control room panel walkdowns and recognition of discrepant equipment paramete,rs was warrante . Communications between operators and instrument and control tun '.icians were excellent during performance of surveillance test activitie .

Operator response to annunciators was acceptable. The inspectors observed that most operators promptly acknowledged alarms and reviewed annunciator procedures as alarms were received. During surveillance testing on the CS system, the inspectors observed that some annunciators received web not listed as expected alarms in the test procedure. Shift management explained that annunciators for pump starts or trips were not generally in procedures since the alarms were anticipated as a result of operator actions. However, during performance of an emergency core cooling system integrated surveillance test, the inspectors identified that the #14 residual heat removal service water j (RHRSW) pump trip annunciator did not come in as expected during the test. The j licensee initiated a work order to investigate the annunciator proble j l

. In general, pre-job and infrequent evolution briefings were detailed. With one exception, contingency actions were planned and discussed. Participants had a !

common understanding of the tasks as evidenced by controlled execution of the )

activities. However, the inspectors noted that the shift supervisor forgot to i discuss contingency actions for excessive leakage during the pre-job briefing for control rod drive (CRD) changeouts. After the inspectors brought this oversight to the shift supervisor's attention, the briefing was reconvened to discuss the issu The inspectors noted %t prior to the first briefing, the shift supervisor and control room operators had reviewed the abnormal procedure for excessive leakag . During observations of work activities described in Section M1,1, the inspectors independently verified that numerous isolation tags were appropriately placed on equipment in the plant and handswitches in the control room. The inspectors did not identify any tagging discrepancie c. Conclusions Operator performance during routine and outage-related activities was acceptabl Improvements were noted in the tumover process and communications. No discrepancies were identified during review of isolation tags on equipment. In general, pre-job and infrequent evolution briefings were detailed. However, the inspectors identified two examples of inattention-to-detail by the reactor operators during control room panel walkdown . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ - -

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01.2 Shutdown Risk Consideration in Refuelina Outaae Plan Inspection Scope (IP 71707)

The inspectors reviewed the licensee's refueling outage schedule and equipment maintenance windowr to verify that outage risk perspectives were appropriately considered. The follodng documents were reviewed:

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Operations Manual C.3, Revision 14, " Shutdown Procedure";

. 1998 Refuel Outage NUMARC 91-06 Review;

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" Fire Protection Practices: Cold Shutdown vs Operations," dated March 6,1998;

. Technical Specification (TS) 3.5.E.1; and

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System Window Schedule dated March 12,1998 (and daily thereafter). Observations and Findinas The inspectors met with the maintenance superintendent, scheduling personnel, and probabilistic risk assessment experts to discuss the refueling outage schedule and anticipated periods of increased risk. The inspectors made the following observations:

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The licensee formed an interdepartmental outage risk management team to ensure that the principles described in the outage management guidelines were reflected in the planned outage schedul .

Equipment operability and availab!!ity requirements listed in Operations Manual C.3 were followed or deviations from the guidelines were appropnately dispositione .

Periods of high risk occurred during divisional testing. The licensee conservatively assumed that the equipment would be unavailable during this period and assured appropriate attemate equipment was availabl .

Controls were placed on changes to the schedule caused by emergent work or other problems encountered during the work activities. The changes in the schedule were re-evaluated for potential impact on the original risk assessmen .

The licensee conducted two outage status meetings each day to discuss current status of maintenance, modification, and testing activities. Concems such as coordination of activities between departments were also addressed. Deviati" from the scheduled work for the day were discussed in detai Conclusions The inspectors concluded that the licensee conservatively applied shutdown risk concepts during the planning and execution of the 1998 refueling outage. The

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( implementation of the outage plan was being conducted effectively and in a controlled l manner.

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l 01.3 Preparations for the 1998 Refuelino Outaae l Inspection Scope (IPs 61726. 62703. 71707. and 71750) '

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The inspectors observed several refueling outage preparation activities to assess the ,

licensee's readiness for the outage; specific comments are provided belo ' Observations and Findinas

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Shutdown and disassembly planning meeting: The participants discussed the hourly plan for the reactor shutdown and disassembly of the reactor vessel components. The discussion was helpful, in that the participants identified some incorrect sequences of activities. Items such as coordination between departments and missing details were addressed to ensure all workers had a common understanding of the task l

. Operators shutdown training: The inspectors attended two sessions conducted in the simulator. Operators performed a simulated shutdown using the instructions specified in the shutdern procedures and identified problems such as difficulty performing turbine testing during the shutdown evolution and conflicts with referenced procedures. Recommended changes were incorporated into the final schedule and/or procedure . Deferred work order (WO) meeting: Engineering, operations, maintenance, and 4 scheduling personnel reviewed the WOs classified as outago-related but not currently scheduled to be performed during the 1998 refueling outage. The licensee evaluated the impact on equipment and system operability if the work was delayed until the next outage. The 48 deferred WOs were prioritized for possible inclusion in the current outage if resources permitted. The inspectors reviewed the deferred WO list and identified no equipment operability concerns, I should the WOs not be performed during the current outag . Initial equipment isolation meeting: The purpose of this meeting was to prioritize the equipment isolations needed by maintenance and engineering personnel during the first five days of the outage. This approach enabled operations personnel to better coordinate activities and resulted in a relatively smooth transition from power operations to outage wor Conclusions The pre-refueling outage activities were beneficial to the coordination and execution of outage work. The workload for operations personnel during the power reduction and first days of the outage was managed effectively as a result of the pre-outage isolation and vessel disassembly meetings. The shutdown training provided to the operators was effective, in that several discrepancies with the shutdown procedures and scheduled activities were identified and resolved prior to tt .s actual shutdow I

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01.4 Power Reduction and initial Shutdown Activities Inspection Scope (IPs 61726 and 71707)

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On March 20,1998, the licensee commenced the Cycle 19 refueling outage. The l inspectors observed portions of the power rede: tion and initial shutdown activities as discussed below. The following documents were also reviewed:

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Operations Manual C.3, Revision 13, " Shutdown Procedure"; l

. Surveillance Test 0081, Revision 26, " Control Rod Drive Scram insertion Time Test";

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Surveillance Test 2140, Revision 8, "De-inerting Primary Containment"; and

. TS 3.7.A. ! Observations and Findinas l

The inspectors attended the pre-job briefings for two operations crews involved with the shutdown. The shift supervisors discussed the shutdown evolution, including the i sequence for additionel testing, and reviewed cautions for reactivity management and i expectations for core monitoring and hot standby operation. Expectations for i

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self-checking, controlled manipulations, conservative decision-making, and ,

communication techniques were also discusse l The inspectors observed good procedure adherence and use of three-way repeat-back communication techniqu0. Juring surveillance tests conducted during the shutdow Single control rod insertion testing was conducted in a slow, deliberate manner. The operators monitored reactor power and nuclear instrumentation and maintained a questioning attitude. For example, operators noted that CRD 34-19 would not insert beyond position 02 with increased drive flow. This same CRD demonstrated similar behavior during the reactor scram on November 25,1997. The operators initiated a work orchr for maintenance personnel to inspect this CRD during the outag The inspectors verified that shutdown activities were performed in accordance with the

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instructions specified in shutdown Procedure C.3 and that TS-required surveillance tests were completed prior to the mode change. No performance concerns were identified during this evolution. However, the inspectors noted that the operators entered a 7-day LCO and not the required 24-hour LCO as specified in TS 3.7.A.5.b when drywell

, de-inerting commenced at about 11:00 a.m. on March 20,1998. The inspectors asked l the lead reactor operator about this apparent discrepancy. At the same time, the shift

manager entered the control room, stated that they were in a 24-hour LCO, and l requested that the operator correct the logbook. The inspectors were satisfied that the

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shift manager was aware of the incorrect LCO entry and that the actions to satisfy the LCO would have been completed within the 24-hour period.

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. Conclusions Operations personnel conducted the shutdown in a well-coordinated, controlled manner and in accordance with procedure O1.5 Conduct of Fuel Movements Inspection Scope (IP 71707)

The inspectors observed portions of several activities associated with refueling the reactor. These activities included removal and installation of used and new fuel j assemblies, local power range monitors, fuel assembly channels, control rod blades, fuel !

support pieces, and blade guides. In addition, the use of the underwater camera, maintenance of fuel accountability records, and inspections of used fuel assemblies were observed. The inspectors reviewed the following documents:

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Operations Manual Section D.1-05, Revision 0, " Accountability";

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Operations Manual Section D.2-05, Revision 4, " Reactor and Core Components -)

Handling Equipment, Tools and Equipment Operation"; j

Procedure 9007, Revision 21, " Procedure for Moving Fuel into, Out of, and Within the Core"; and

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Procedure 9009, Revision 15, " Procedure for Moving Fuel Within the Fuel Storage Pool." Observations and Findinas All of the activities observed were conducted well. A total of about 850 separate fuel or j other component moves were completed in the reactor vessel and fuel storage pool. No l errors were made in any of those moves. Before a fuel assembly was latched and before an assembly was placed in a core or fuel pool location, the refueling bridge operator, the fuel handling supervisor, and the fuel accountability recorder each concurred that the location was correct. In one case while the inspectors were observing, the refueling

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bridge operator lowered the bridge grapple mast over the wrong fuel storage pool location l to retrieve a fuel assembly; however, the supervisor noticed the error before the assembly l was latched and corrected the operator. Continuous communication with the control room was maintained and a control room reactor operator independently verified that the l fuel handling personnel were performing the proper steps in the sequence checklist.

l The inspectors observed proper use of the fuel location tagboard on the refueling floor, the fuel handling supervisor's procedure checklist, and the accountability recorder's verification checklist. A new initiative of maintaining the verification checklist on a personal computer both on the refueling floor and in the control room was used for the first tim All refueling operations observed were done with care and deliberation. Operators demonstrated diligence in protecting the fuel and other core components from damag l~

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A variety of fuel handling tools were used in the various steps and all were properly inspected and tested prior to use and used in the manner for which they were designe Conclusions Refueling operations, which included about 850 separate fuel or core component moves, were conducted in a careful, delterate, and error-free manne O2 Operational Status of Facilities and Equipment O Enaineered Safety Feature System Walkdowns The inspectors used IP 71707 to perform a detailed walkdown of the accessible portions of the CS, emergency filtration, and station battery systems. Minor housekeeping issues identified during the walkdown were brought to the attention of the system engineer These issues were promptly corrected by the licensee. No operability concems were identifie O2.2 inspections ofInaccessible Areas The inspectors used IP 71707 to tour areas of the plant that are normally inaccessible during reactor operation. The areas inspected included the dr)well, torus, condenser room, main steam tunnel, and steam jet air ejector room. No operability concems were identified. The inspectors used Procedure 2154-26, Revision 36, "Drywell Prestari Valve Checklist," and drawings from Section 15 of the Updated Safety Analysis Report (USAR)

to access the material condition and position of select residual heat removal (RHR),

instrument air, .ud main steam valves. No operability concems were note O3 Operations Procedures and Documentation 0 Review of Locked Emeraency Core Coolina System (ECCS) Valves Inspection Scope (IP 71707)

During this inspection period, the inspectors performed a review of locked ECCS valve The purpose of this review was to verify that the valves were locked in accordance with procedures. The inspectors reviewed the following documents:

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USAR Section 6.2, " Emergency Core Cooling System";

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USAR Section 15, "USAR Drawings";

Safety Review Item (SRI)96-003, " Locked Valve Program improvaments and Associated USAR Changes," Revision 0;

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Administrative Work Instruction (4AWI) 04.04.01, Revision 11, " Equipment isolation";

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Piping and Instrumentation Diagram (P&lD) M-115, " Nuclear Boiler System-Steam Supply," Revision AR;

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P&lD M-120, " Residual Heat Removal System," Revision BE; I

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P&lD M-121, " Residual Heat Removal System," Revision BF;

• P&lD M-122, " Core Spray System," Revision AF;

P&lD M-123, "(Steam Side) High Pressure Coolant injection Sys," Revision AD;

P&lD M-124, "(Water Side) High Pressure Coolant injection System," Revision X;

Procedure 1401-1, Revision 19," Locked Valve Alignment";

Procedure 2154-10, Revision 21, "High Pressure Coolant injection System Prestart Valve Checklist";

Procedure 2154-11, Revision 15, " Core Spray System Prestart Valve Checklist";

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Procedure 2154-12, Revision 33, " Residual Heat Removal System Prestart Valve Chacklist"; and

. Procedure 2154-26, Revision 35, "Drywell Prestart Valve Checklist." Observations and Findinas The inspectors verified that ECCS valves assumed locked per the USAR were included in the licensee's procedures and prints. The inspectors verified that the positions of the locked ECCS valves as shown on the P&lDs were consistent with the requirements of the applicable prestart valve checklist and were in accordance with the valve locking !

requirements of 4 awl-04.04.01. Accessible ECCS valves were verified to be locked in ;

the correct positio Miscellaneous Operations issues 08.1 Surveillance Reauirement With No Correspondino LCO Inspection Scope (IPs 37551. 61726,62703. 71707. 71750. and 92700)

During review of an emergency diesel generator (EDG) starting air system preventive maintenance work order, the inspectors noted that the licensee did not enter an LCO for an inoperable starting air compressor (SAC). The inspectors reviewed the following documents:

. TSs 3.9.B.3 and 4.9.B.3.b;

• P&lD NX-9216-4, Revision C, " Air Starting System";

. Surveillance Test 0187-01, Revision 26, "11 Emergency Diesel Generator /11 Emergency Service Water Pump System Tests";

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SRI 90-022, " Acceptability of EDG Air Start System Isolation for Maintenance";

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Procedure 7180, Revision 13, " Diesel Generator System Instrument Maintenance Procedure." Observations and Findinas The EDG starting air system consists of two subsystems, each containing dual air start motors, three air tanks, and two starting air compressors. The SACS maintain the starting air tanks at a required minimum pressure. When one of the two SACS becomes or is made inoperable, the licensee enters an " administrative" LCO but does not declare the associated EDG inoperable. The licensee does not consider the SACS as support equipment since EDG operability is dependent on the air pressure in the tank Each month, TS 4.9.8.3.b requires the licensee to verify the capability of the EDG SACS to recharge the air tanks. 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 criterion was not met. This is an Inspection Followup Item (IFl 50-263/98004-01(DRP)) pending further review by the Office of Nuclear Reactor Regulation (NRR).

08.2 (Closed) Violation (VIO 50-263/95011-03(DRP)): This violation involved two examples of failure to follow procedures. On October 12,1995, a plant equipment operator found the B RHR drywell spray manual isolation valve, RHR 74-2, unlocked and closed. The required position was locked open. The valve had been incorrectly positioned since October 1994. The licensee determined that operations persaanelincorrectly completed the RHR pre-start checklist and work request associated with b,olation Tag 94-8031 The licensee's immediate corrective actions included placing the valve in the correct position and verifying valve positions on several safety-related systems. The long-term corrective actions included: (1) discussion of the event with operations personnel; (2) additional training in the valve line-up process; (3) enhancements to the " hold and secure"(equipment isolation) card process; (4) clarification of expectations on signature transfers when using a working copy of a procedure; and (5) re-evaluating the locked-valve process. The inspectors noted that in subsequent refueling and forced outages the licensee provided additional time for operations personnel to perform system checklists. The inspectors concluded that the licensee's immediate and long-term corrective actions were appropriate to address the violatio The licensee also revised the locked valve procedure. However, in October 1997, general quality services personnel identified that two valves in the CRD system should have been locked per design drawings to prevent overpressurization. Condition Report 97002939 was initiated and the licensee planned to review other criteria that may be required for valves to be locked. This issue is an Inspection Followup item (IFl 50-263/98004-02(DRP)) pending review of the licensee's corrective actions. As l discussed in Section O3.1, the inspectors reviewed the locked valve checklist and verified that valves were locked as required by the USAR and TS ._. ._

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l 08.3 (Closed) Licensee Event Report (LER 50-263/95007(DRP)): Mispositioning of Division B drywell spray block valve. This event was the subject of a violation as discussed in !

Inspection Reports No. 50-263/95011(DRP) and No. 50-263/95012(DRP). The licensee's I corrective actions and evaluation of the causes of the event were appropriate and thorough. The inspectors had no further concem II. Maintenance M1 Conduct of Maintenance l

M1.1 Observation of Maintenance and Surveillance Test Activities l 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 test procedures or WOs listed as well as the appropriate USAR sections pertaining to the activitie Observations and Findinas In general, the inspectors observed that the work associated with these activities was conducted in a professional and thorough manner. Pre-job briefings were thorough and included discussions on radiation protection control measures and worker practice When necessitated by the activity, communication between technicians and control room operators was established, and observed to be effective. All work observed was performed with the work package present and in active use. Technicians were experienced and knowledgeable of their assigned tasks. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedur The following work was observed. Specific concems or observations are provided where appropriat . WO 9705672, " Replace RV-1745 [ relief valve]"

On March 31,1998, the inspectors observed restoration activities on the A Train CS system and identified that maintenance personnelinstalled the relief valve intended for the B Train (RV-1746). The A Train CS was not operable at the time of the discovery. The licensee initiated a condition report to invest; gate and determine the root cause. The inspectors noted that the WO instructed the maintenance personnel to install a relief valve from purchase order PL 6242. In addition, a test engineer note, on the front cover of the instructions within the work order, indicated that the valve with Senal Number N89658-00-0001 would be installeo in CS Train A; however, the valve (Serial Number N89658-00-0002)

intended for CS Train B was installed inadvertently. The purchase order record indicated that two valves were procured for the project. Engineering personnel l stated that RV-1745 and RV-1746 were identical in design and that the identifying tags on the new valves were used to match pre-installation setpoint testin However, for both valves the pre-installation setpoints were identical. Therefore,

the engineers revised the work order to reflect the switched valves. This error was administrative; however, it showed a lack of attention-to-detail by the maintenance personnel. The licensee's corrective actions were acceptable and included review of supervisory and engineering oversight of work activities.

. WO 9705674," Replace Relief Valve RV-2993" and modification 96Q180-03 ,

i The condensate service water system functions as a keep-fill system for the RHR and CS systems. To facilitate replacement of a relief valve and to maintain operability of the RHR and CS systems, the licensee temporarily aligned demineralized water through a hose to the condensate service water pressurizing i stations. Instructions within the WO identified this hose as a jumper / bypass. The l inspectors questioned whether a 10 CFR 50.59 safety evaluation screening was I performed and were told that the activity was covered by the modification proces The inspectors met with engineering personnel and determined that a safety evaluation was performed for the replacement of the relief valves, not for the installation process. The licensee performed a screening for the temporary l installation of the hose and determined that a formal 10 CFR 50.59 safety '

evaluation was not required. The inspectors concluded that this example demonstrated a vulnerability in the licensee's modification and jumper / bypass processes. The licensee stated that an earlier self-assessment of the 10 CFR 50.59 program identified similar concerns.

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WO 9800406, " Perform Electrical PM [ preventive maintenance) on 11 Recirc MG Set Motor / Exciter"

. WO 9800143, " Replace PS-2-3-52A" and Modification 97Q150, Revision O,

"PS-2-3-52A Replacement" and associated work orders The purpose of the modification was to replace the existing ASCO model pressure switch, PS-2-3-52A, with a Static O-ring model. As discussed in Inspection Report No. 50-263/97006, the existing pressure switch experienced high setpoint drift and a diaphragm failure. The inspectors observed maintenance personnel install the new pressure switch. The inspectors noted good procedure adherenc For example, the electrical work did not proceed until the instrument and control technician replaced the sensing line tubing, since the steps in the procedure were required to be performcd in sequence. The inspectors also noted that the quality control inspector verified appropriate parts were procured and temiinations were made correctly.

. WO 9800426, " Install and terminate cable for RWCU [ reactor water cleanup) Line Break isolation Modification" The inspectors observed portions of the installation, including wire termination The licensee evaluated the potentialimpact of a high energy line break when associated barriers were breached for conduit installatio l

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WO 9801367, " Reset Pressure Setpoint for RV-11-39A & RV-11-39B" l

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Surveillance Test 014, Revision 12, " Reactor Building to Torus Vacuum Breaker Operability Test" l l

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Surveillance Test 0073, Revision 10, " Shutdown Margin Demonstration" I i

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Surveillance Test 0086, Revision 20, "SBLC [ standby liquid control] Refueling l l Tests" l .

Surveillance Test 0137-07A, Revision 10, " Reactor Steam Supply Valve Leak Rate Testing by Pressurizing the Reactor with Air or by Pressurizing the Steam Lines with the MSL Plugs installed"

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Surveillance Test 0212, Revision 17, " Rod Worth Minimizer Operability Test"

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

. Surveillance Test 1043-1, Revision 0, " Turbine Stop Valve Tightness Test Done During Plant Shutdown"

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. Surveillance Test 1428, Revision 2, "RPV [ reactor pressure vessel] Reference Leg Backfill System Maximum Flow Check" The inspectors observed the pre-job briefing held in the control room between the operators and instrument and control technicians. Potential effects on other instrumentation were discussed and contingency actions were planned if as-found data were outside limits. Technicians were knowledgeable of surveillance requirements and performed work activities in a professional manner.

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. Procedure 4152PM, Revision 3, "SBLC System Explosive Valves"

. Procedure 7090, Revision 6, "Recirc Flow Control System Calibration"

. Procedure 9214, Revision 13, "Detension RPV Studs" The inspectors observed the pre-job briefing which included step-by-step review of the instructions in the procedure and a demonstration using a tensioner.

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Radiation protection personnel discussed the radiological hazards and l precautions for working in a highly contaminated, locked high radiation area. The inspectors noted that the licensee followed the established heavy load path when transporting the carousel and tensioners from the refueling floor to the reactor vessel head. Good teamwork between the maintenance and radiation protection personnel was observed during this evolutio * Procedure 9253, Revision 15, " Wet Transfer of Steam Separator (Installation)"

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Procedure 9279, Revision 10, " Fuel Pool, Separator / Dryer Pool & Reactor Well Shield Blocks (Installation)"

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Procedure 9309, Revision 16, "Changeout Selected CRD's Maintenance" and Procedure 9019, Reviden 15, "Changeout Selected CRD's Operations" Conclusion in general, the observed maintenance and surveillance activities were conducted in accordance with instructions in procedures and in a professional manner. Pre-job briefings were thorough and supervisory oversight was appropriate. Engineering personnel provided excellent support to the maintenance staff. A weakness in the modification and jumper / bypass program interface was identifie M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Outstandina Work Items Inspection Scope (IPs 37551. 62703. and 71707)

The inspectors periodically monitored the backlog of maintenance WOs with emphasis on control room problems. The inspectors evaluated whether the backlog appeared to be manageable and whether sufficient attention was given to resolving operations issue Observations and Findinas The most recent data available (obtained prior to the refueling outage) to the inspectors indicated the following:

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The total non-outage WO backlog remained steady at about 200 item Corrective maintenance represented only a small fraction of this total since WOs include all corrective maintenance, minor maintenance, and modification item The number of non-outage WOs had not varied more than 10 percent in the previous six months, indicating that work was not accumulatin .

The outstanding non-outage safety-related corrective maintenance backlog was about 50 items. These items are reviewed periodically by management personnel to monitor progress on completion of the task .

There were a total of 14 identified control room deficiencies, as indicated by a count ofinformation tags and work request stickers. These included annunciator and instrumentation deficiencies, pending modifications on valves, and an outstanding, required post-maintenance test that the licensee plans on performing during the refueling outage. The inspectors concluded that these problems were minor and did not significantly impact operations personnel. The inspectors noted that significant control room deficiencies were discussed at the plan-of-the-day meeting and were typically resolved within a few day .

There were six operator work-around concems that required compensatory operator actions or could complicate the response to events. The licensee plans j 16

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to work on two items, replacement of the A standby gas treatment system flow indication and providing the ability to operate all drywell fans in the post-scram mode, during the current refueling outage. Resolution of the remaining items were being pursued by engineering personne . There were 31 installed jumper / bypasses. The licensee planned to address 15 of these items during the current refueling outag . General material condition of plant equipment was excellent and unexpected entries into LCOs due to equipment problems were infrequen . Conclusions The backlog of corrective maintenance WOs was relatively small and stabl3. Priority work and control room deficiencies received appropriate management and engineering staff attention. Equipment failures which led to TS LCOs were infrequent and rapidly resolved. Work was performed in a timely manner and was generally completed correctly the first time. Overall, a review of the maintenance backlog indicated a strong, well-implemented maintenance progra M8 Miscellaneous Maintenance issues

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M (Open) Unresolved item (URI 50-263/97003-07(DRP)): Discrepancy between TS and i TS bases with respect to the conduct of surveillance tests. On February 27,1998, the ;

NRR project manager informed the licensee that the use of a "-25" percent band on I surveillance intervals was contrary to the requirements in TS 4.0.8. A conference call l was conducted on March 2,1998, for the licensee to provide additional information regarding the surveillance program. The licensee immediately revised the surveillance testing program to disallow the "-25" percent band on surveillance intervals. This item will remain open until the licensee receives written notification that the use of the "-25" percent band on surveillance intervals is contrary to the requirements of T M8.2 (Closed) Licensee Event Report (LER 50-263/96007(DRP)): Reactor scram resulting from electrical short in the generator condition hydrogen monitor. This event was d;scussed in detail in Sections 01.3 and M2.2 of Inspection Report No. 50-263/96006(DRP). The inspectors had no concems with the licensee's actions and evaluatio M8.3 (Closed) Licensee Event Report (LER 50-263/97008(DRP)): Inappropriate use of the 25 percent tolerance for periodic actions in Section 3 of the TSs. The licensee canceled the TS interpretation that allowed the inappropriate use of 25 percent tolerance on compensatory action intervals. This issue was the subject of a licensee-identified, non-cited violation (50-263/97003-04(DRP)).

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111. Enaineerina E1 Conduct of Engineering E1.1 Minor Water Hammer Event in the Hiah Pressure Coolant Iniection (HPCI) Pipina Inspection Scope (IPs 37551. 61726. and 71707)

On February 16,1998, operations personnel performed a surveillance test on the HPCI system. While cycling the discharge valve, MO-2068, the operators heard a low rumble 4 and suspected that a water hammer occurred. The inspectors reviewed the licensee's response to this event and reviewed the following documents:

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Condition Report 98000413, "Possible minor water hammer when cychng MO-2068 during test";

. Information Notice 91-50, Supplement 1, " Water Hammer Events Since 1991"; l

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. Information Notice 89-80, " Potential for Water Hammer, Thermal Stratification, ;

and Steam Binding in High Pressure Coolant injection Piping"; and

. Surveillance Test 0255-06-IA-1, Revision 40, "HPCI System Test with Reactor l Pressure at Rated Conditions," completed on February 16,199 Observations and Findinas i Following the suspected water hammer, operations personnel inspected the accessible portions of the HPCI piping and did not identify any concems with hangers or supports. A thermometer located on the extemal surface of the HPCI discharge piping upstream of MO-2068 showed a slight increase in temperature. Based on the results of the i inspections and no indication of backleakage through MO-2068, operations personnel continued the test after notifying the system enginee The inspectors leamed of the incident on February 18,1998, and inquired about the root cause of the event and operability of the system. A documented operability evaluation was not performed since a condition report had not been written. Following a discussion j with the inspectors, the system engineer requested assistance from maintenance engineers and initiated Condition Report 98000413. A work order was created to monitor motor current during a subsequent valve stroke to verify proper limit switch setting Engineering personnel also concluded that backleakage through the valve could cause a void in the piping. A decision was made to cycle the valve on February 27,1998, to confirm the presence of a void or limit switch problems. Operators cycled the valve and heard a low rumble. Engineering personnelin the torus catwalk area noted that the injection piping moved about 1-inch at the hanger located at the end of the horizontal ru Operations personnelinspected the HPCI injection piping including a section of pipe in the main steam chase room. No problems were identified. The licensee performed a more detailed operability evaluation, including an analysis of allowable stresses. A work order was generated to examine the valve during the current refueling outag _

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The inspectors observed the February 27,1998, valve stroke in the control room and l independentlyinspected the accessible portions of the piping and supports. No concems l were identified. The inspectors reviewed the operability evaluation and agreed wit 1'ae i licensee's assessmen j l Conclusions i

The root cause of the February 16,1998, minor water hammer in the HPCI injection i piping was not aggressively pursued by engineering personnel until questioned by the inspectors. The subsequent evaluation and corrective actions were appropriat l i

E2 Engineering Support of Facilities and Equipment j

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E2.1 Instrument Air Check Valves .

i Inspection Scope (IP 37551) l The inspectors reviewed the licensee's check valve program to verify that instrument air system check valves were included. The following documents were reviewed:

. P&lD M-121, Revision, BF, Residual Heat Removal System;

• P&lD M-122, Revision, AF, Core Spray System;

• P&lD M-131, Sheets 12 through 14, Instrument Air- Reactor Building and Drywell;

.- Surveillance Test 0003, Revision 13, "Drywell High Pressure Scram and Group 2, 3, & SCTMT [ secondary containment) Isolation Test;  ;

. Surveillance Test 0137-27, Revision 5, "TIP [transversing incore probe] System isolation Valves Local Leak Rate Test";

. Engineering Work Instruction 08.16.01, Revision 0, " Check Valve Program"; and

. Engineering Work Instruction 09.04.01, Revision 3," Inservice Testing Program." Observations and Findinas l The inspectors selected 27 check valves located in the instrument air system and verified that testing as specified in the licensee's inservice testing program and as required by 10 CFR Part 50, Appendix J, was accomplished. The inspectors performed a detailed review of Surveillance Tests 0137-27 and 0003 and verified that the acceptance criteria were consistent with licensing and design information. However, the inspectors identified j that the transversing incore probe inboard containment isolation check valve,626-1, as !

noted in P&lD 131, Sheet 14, was incorrectly tagged as 226-1. The system engineer !

stated that this mistagged valve was identified previously; the inspectors verified that a j condition report addressed this condition. The localleak rate procedures also listed the j valve incorrectly. The inspectors verified that, although labeled incorrectly, the valve was j properly teste I I

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i Conclusions Based on the samole reviewed, no concems with testing of instrument air check valves were identifie I E8 Miscellaneous Engineering issues l

E (Closed) Inspection Followuo item (IFl 50-263/96003-05(DRP)): Modifications in the I turbine building to correct high energy line break barrier discrepancies. The licensee identified that a high energy line break on the turbine floor or in the feedwater pump area would expose non-environmentally qualified equipment to a harsh environment. During the April 1996 refueling outage, the licensee modified an open stairway and installed j several high energy line break barrier doors. The inspectors had no concems with the licensee's corrective action E8.2 (Closed) Unresolved item (URI 50-263/96003-06(DRS)): Questions on acceptability of

- using leak-before-break methodology in operability evaluations. In a letter dated i February 11,1997, (Enclosure 2 to the cover letter for this inspection report) the Office of i Nuclear Reactor Regulation (NRR) officially stated that the use of leak-before-break i methodologies was not acceptable under any circumstances unless previously approved l by the NRC. The inspectors discussed this issue with licensee management in April and I June 1997. The licensee raised several questions regarding the NRC position which '

were forwarded to NRR for consideration. On March 6,1998, the inspectors notified i licensee management that the NRC position, as stated in the February 1997 letter,

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remained valid. In summary, the use of leak-before-break methodologies changed the failure assumptions of licensing and design basis events and this was considered unaccepiable by the NRC. The licensee immediately ceased the practice of relying on high-energy-line-break watches and began requiring operability evaluations for potentially l affected equipment when barriers were breache I E8.3 (Closed) Unresolved item (URI 50-263/96007-03(DRP)): Licensee's actions to address a !

RWCU line break discrepancy. The licensee identified that a reactor water clean-up line break at lower reactor power was not bounded by assumptions in the USAR. The licensee's immediate actions included proceduralizing manual operator action to isolate RWCU on break detection and submitting a TS amendment request to decrease the reactor water coolant dose equivalent lodine-131 concentration limit. This issue was forwarded to NRR for further review. The results of this review were documented in a letter dated August 8,1997, to J. Crobe, then Acting Director of the Division of Reactor -

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Safety, from John Hannon, then Project Directorate ill-1, NRR, in which the NRC concluded that the Ikonsee's actions were acceptable. The licensee plans to withdraw the TS amendment request once a modification to the RWCU isolation logic circuitry is completed to provide automatic isolation of the system if a break should occur. The inspectors had no further concem E8.4 { Closed) Licensee Event Report (LER 50-263/96003(DRP)). Revision 0: During a re-analysis of the postulated high energy line break event, an error was found in the existing analysis. This issue is discussed in detail in inspection Report No. 50-263/96003(DRP). Two followup items were opened in that report to address the licensee's corrective actions and use of leak-before-break methodologie I

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E (Closed) Licensee Event Report (LER 50-263/%008(DRP)). Revision 0: Reacter water clean-up line break reanalysis due to an error discovered during re-evaluation. This issue was discussed in Section E2.1 of Inspection Report No. 50-263/%007. Two followup items were opened in that report to address the licensee's corrective actions for this issu 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 the maintenance, engineering, and operations pers9nnel during the refueling outage. Radiation protective technicians discussed radiation fields and contamination levels during pre-job briefings and at the drywell personnel access point. The technicians monitored job-sites and provided guidance to the workers. The inspectors also noted excellent planning and execution of the removal of high!y radiated RWCU pipin S1 Conduct of Security and Safeguards Activities (IP 71750)

During normal resident inspection activities, routine observations were conducted in the l areas of security and safeguards activities. The inspectors toured the central alarm station, secondary alarm station, badge issue area, guard house weapons locker, security l battery room, and the security diesel room. No concems were note S8 Miscellaneous Security and Safeguards issues S (Closed) Inspection Followup Item (IFl 50-263/97201-01(DRS)): Aspect of protective strategy not evaluated due to radiological conditions. On April 13,1998, the inspectors observed a security drill which demonstrated that the area in question was not a security conce V. Manaaement Meetinas X1 Exit Meeting Summary On April 20,1998, the inspectors presented the inspection results to members of licensee managemerit. 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 identified.

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PARTIAL LIST OF PERSONS CONTACTED Licensee M. Wadley, Vice President Nuclear Generation

• M. Hammer, Plant Manager

• B. Day, Training Manager )

• J. Fenton, Superintendent, Plant Scheduling

• J. Grubb, Superintendent, Electrical Design Engineering K. Jepson, Superintendent, Chemistry & Environmental Protection

• L. Nolan, General Superintendent Safety Assessment

• M. Onnen, General Superintendent Operations 4

• E. Reilly, General Superintendent Maintenance

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• C. Schibonski, General Superintendent Engineering l

• A. Ward, Manager Quality Services ]'

L. Wilkerson, Superintendent Security J. Windschill, General Superintendent, Radiation Protection ,

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

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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observations IP 62703: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-263/98004-01(DRP) IFl Question concerning TS 3.9.B.3 requirement for inoperable i starting air compressor  !

I 50-263/98004-02(DRP) IFl Licensee's evaluation of general quality services identified )

locked valve discrepancies <

Closed 50-263/9501103(DRP) VIO Two examples of failure to follow procedure 50-263/96003-05(DRP) IFl Modifications in the turbine building to correct high energy line break barrier discrepancies .

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50-263/96003-06(DRS) URI Questions on acceptability of using leak-before-break methodology in operability evaluations 50-263/96007-03(DRP) URI Licensee's actions to address a RWCU line break ,

discrepancy 50-263/97201-01(DRS) IFl Aspect of protective strategy not evaluated due to radiological conditions 50-263/95007(DRP) LER Mispositioning of Division 8 drywell spray block valve 50-263/96003(DRP) LER During a re-analysis of the high energy line break an error was found in the existing analysis 50-263/96007(DRP) LER Reactor scram resulting from electrical short in the generator condition monitor 50-263/96008(DRP) LER Reactor water clean-up line break reanalysis due to an error discovered during re-evaluation 50-263/97008(DRP) LER Inappropriate use of the 25 percent tolerance for periodic actions in Section 3 of the Technical Specifications

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Discussed

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50-263/97003-07(DRP) URI Discrepancy between TS and TS bases with respect to the i conduct of surveillance tests

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I LIST OF ACRONYMS USED 4AWI Administrative Work Instruction !

CFR Code of Federal Regulations CRD Contro! Rod Drive CS Core Spray DRP Division of Reactor Projects DRS Division of Reactor Safety ECCS Emergency Core Cooling System i EDG Emergency Diesel Generator HPCI High Pressure Coolant Injection IFl Inspection Followup Item LCO Limiting Condition for Operation LER Licensee Event Report NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation NSP Northern States Power P&lD Piping and Instrumentation Diagram PM Preventive Maintenance psig Pounds-per-square inch-gauge RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RPV Reactor Pressure Vessal ,

RV Relief Valve

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RWCU Reactor Water Clean-Up l

SAC Starting Air Compressor  !

SBLC Standby Liquid Control SCTMT Secondary Containment SRI Safety Review Item TS Technical Specification URI Unresolved item USAR Updated Safety Analysis Report VIO Violation WO Work Ocder

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pa "'% Enclosure 2 UNITED STATES 3 .

.., g NUCLEAR REGULATORY COMMISSION 5 3 REGION til E

iE 801 WARRENVILLE ROAD k, / LISLE. ILLINOIS 60532-4351

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February 11, 1997 MEMORANDUM T0: Geoffrey E. Grant, Director Division of Reactor Safety, RIII FROM: John N. Hannon, Director Original signed by John N. Hannon Project Directorate III-1 Division of Reactor Projects - III/IV, NRR SUBJECT: RESPONSE TO THE TASK INTERFACE AGREEMENT (TIA) REGARDING ACCEPTABILITY OF USE OF LEAK BEFORE BREAK ANALYSIS FOR ENVIRONMENTAL QUALIFICATION OF EQUIPMENT FOR OPERABILITY ,

EVALUATIONS AT MONTICELLO (AIT 96-0359) l

By a letter dated October 18, 1996, you requested NRR staff to evaluate and determine the adequacy of applying leak-before-break (LBB) technology to justify the environmental qualifications (EQ) of equipment for operability 3 evaluations associated with high energy line break (HELB) analyses at Monticello Nuclear Generating Plan The staff has determined that this application of LBB technology is inappropriate for several reasans. We have discussed the results of our review with Mr. Joel Guzman of your staff. Our detailed response is provided in the attachment to this memorandu If you have any questions regarding this issue, please contact T. Kim of my staff at (301) 415-139 Docket No. 50-263 Attachment: Response to Request for Technical Assistance l

cc w\att: J. T. Wiggins, RI J. P. Jaudon, RII T. P. Gwynn, RIV

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STAFF RESPONSE TO THE TASK INTERFACE AGREEMENT (TIA)

REGARDING ACCEPTABILITY OF USE OF LEAK BEFORE BREAK ANALYSIS FOR ENVIRONMENTAL QJALIFICATION OF EQUIPMENT FOR OPERABILITY EVALUATIONS AT MONTICELLO (AIT 96-0359)

Backaround In the TIA dated October 18, 1996, the Division of Reactor Safety, Region III informed the NRR staff that Northern States Power, the licensee for the l Monticello Nuclear Generating Plant, was applying leak-before-break (LBB)

l analysis methods for operability evaluations. Specifically, on two separate j occasions in April 1986 and April 1996, the licensee proposed to apply LBB

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methods to a section of the plant's feedwater piping. These evaluation were used to dismiss the possibility of a high energy line break (HELB) which could cause conditions adverse to the environmental qualification (EQ) of two Division II motor control centers and both divisions of 4 kV switchgea l

, These evaluations proposed to justify continued operation of the plant for l l approximately 30 days in 1986 and 6 days in 199 Evaluation The NRR staff was requested by Region III to determine whether or not this

application of LBB methods was consistent with NRC positions on its use. The l NRC has published a significant amount of information on the use of LBB since the early 1980s. NUREG-1061, Volume 3 provides the staff's comprehensive

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technical assessment of LBB analysis. The staff's regulatory position on its {

use was summarized in Federal Register notices dated April 11, 1986, and ;

October 27, 1987, associated with a rule change to 10 CFR Part 50, Appendix A, '

General Design Criteria 4. This change permitted licensees to exclude from their design basis the dynamic effects of high energy pipe rupture when

, analysis reviewed and approved by the staff demonstrate that the probability I

of pipe rupture is extremely low. Additional staff guidance was recently ;

published in the NRC Inspection Manual, Part 9900, " Definition of Leak-Before- l l

Break Analysis and its Application to Plant Piping Systems." i Consistent with the aforementioned staff positions, it has been determined that the licensee's application of LBB analysis methods is not acceptable for the following reasons:

1) The licensee's leak-before-break analysis has not been submitted to the i

, staff for review and approval. Under no circumstances, for either !

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operability determinations or for licensing basis changes, is a licensee I to apply LBB methods without having received prior approval from the NRC l in a safety evaluation repor l 2) It is expected that use of LBB on the feedwater system violates many of the limitations discussed in NUREG-1061, Volume 3. The licensee has not demonstrated that this system is not susceptible to failure via erosion / corrosion degradation, water hammer, or low or high cycle fatigue. In fact, application of LBB has been approved only for Attachment

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pressurized water reactor primary coolant systems, and only for those systems inside primary containment, in which all system-degradation mechanisms have been minimized by the use of appropriate piping materials, water chemistry measures, and specific piping design consideration ) The licensee's application of LBB methods to justify not having I demonstrated adequate EQ of safety-related equipment has not been recognized as appropriate by the staff. The sizing of emergency core cooling systems and equipment EQ were expressly excluded from the approved applications of LBB during the rulemaking associated with the revision to GDC-4. The staff's position at that time was that these evaluations should be based on the most limiting deterministic pipe break. The staff continues to support this position, as noted in the NRC Inspection Manual, Part 9900:

Reanalysis as a result of the use of LBB of the magnitude of these global effects (including temperature and humidity] and their influence on the design of emergency core cooling systems, containment boundaries, and/or the i environmental qualification of electrical and mechanical components is not allowed by the regulation Therefore, the NRR staff concludes that the licensee's application of LBB technology to justify the environmental qualification of safety-related equipment for operability evaluation purposes is not acceptable, i

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