IR 05000266/1998003: Difference between revisions

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{{Adams
{{Adams
| number = ML20217D353
| number = ML20217P600
| issue date = 03/21/1998
| issue date = 04/30/1998
| title = Insp Repts 50-266/98-03 & 50-301/98-03 on 980120-0302. Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering & Plant Support
| title = Ack Receipt of Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-266/98-03 & 50-301/98-03 Issued on 980321.Corrective Actions Will Be Examined During Future Inspections
| author name =  
| author name = Mccormickbarge
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
| addressee name =  
| addressee name = Patulski S
| addressee affiliation =  
| addressee affiliation = WISCONSIN ELECTRIC POWER CO.
| docket = 05000266, 05000301
| docket = 05000266, 05000301
| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-266-98-03, 50-266-98-3, 50-301-98-03, 50-301-98-3, NUDOCS 9803270399
| document report number = 50-266-98-03, 50-266-98-3, 50-301-98-03, 50-301-98-3, NUDOCS 9805060358
| package number = ML20217D341
| title reference date = 04-20-1998
| document type = INSPECTION REPORT, NRC-GENERATED, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| document type = CORRESPONDENCE-LETTERS, OUTGOING CORRESPONDENCE
| page count = 30
| page count = 2
}}
}}


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s U.S. NUCLEAR REGULATORY COMMISSION -
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l l  REGION ll1 l
          @p April 30, 1998 Mr. S. A. Patulski Site Vice President Point Beach Nuclear Plant Wisconsin Electric Power Company 6610 Nuclear Road Two Rivers, Wisconsin 54241 SUBJECT:  NOTICE OF VIOLATION (NRC INSPECTION REPORT NO. 50-266/98003(DRP);
l Docket Nos: 50-266, 50-301 License Nos: DPR-24, DPR-27 l
50-301/98003(DRP))
l Report No: 50-266/98003(DR P), 50-301/98003(DR P)
l Licensee: Wisconsin Electric Power Company l
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Facility: Point Beach Nuclear Plant, Units 1 & 2
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Location: 6612 Nuclear Road Two Rivers, WI. 54241-9516 l
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Dates: January 20 through March 2,1998
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Inspectors: F. Brown, Senior Resident inspector P. Louden, Resident inspector P. Simpson, Resident inspector
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l Approved by: J. W. McCormick Barger, Chief Reactor Projects Branch 7
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9003270399 900321 PDR ADOCK 0500C266    l G  PDR l
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==Dear Mr. Patuiski:==
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This will acknowledge receipt of your letter dated April 20,1998, in response to our letter dated March 21,1998, transmitting a Notice of Violation associated with Inspection Report No. 50-266/98003(DRP); 50-301/98003(DRP). We have reviewed your corrective actions and have no further questions at this time. These corrective actions will be examined during future inspections.
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t      I l  EXECUTIVE SUMMARY
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Point Beach Nuclear Plant, Units 1 & 2
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NRC Inspection Report No. 50-266/98003(DRP); 50-301/98003(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week inspection period by the resident inspector Operations
. The Unit 2 startup on February 7,1998, was conducted well; however, operators continued with unit startup without completely understanding the cause, or identifying all of the effects, of a waterhammer which occurred in the main steam piping during startup preparations. This was indicative of a lack of sensitivity to the potential consequences of waterhammer events. Licensee management initiated a high-level root cause evaluation of the event and the operator response. (Section O1.1)
. Operators were observed circumventing the licensee's work control process by verbally ;
directing adjustments to nonsafety-related control valves during a unit startup. Operators j performing informal troubleshooting caused an unplanned closure of the moisture separator reheater steam flow control valves during a unit shutdown, resulting in a four percent reactor power transient. The operator response to this minor transient was adequate, but the control room command and control roles were not consistent with the !
expectations in the procedure for conduct of operations. (Section O1.2)  !
. Personnel who inspected new fuel assemblies demonstrated appropriate attention-to- l detail. (Section O1.3)
. Operations personnel safely conducted and controlled fuel movements. However, containment work activities lacked coordination, and there was minimal management oversight of containment activities early in the refueling outage. (Section 01.4)
. The reactor coolant pump lube oil collaction systems were found not to be in accordance with the requirements of 10 CFR Part 50, Appendix R, Section 111.0. This condition was identified during the licensee's Appendix R rebaselining project. Effective compensatory actions were implemented and corrective actions were planned. (Section O2.1)
. The licensee procedures for operation of the two units were inappropriate in that they created the potential for sustained operation at a reactor thermal power in excess of the facility license limits. Two examples of a violation were identified. The licensee responded promptly to this inspector finding, and the procedures were revised prior to the exit meeting. (Section O3.1)
. One violation was identified for an engineer who failed to follow the danger tag procedure for operating permits. No training had been provided to engineers on the operating permit controls. Corrective actions were taken by the licensee prior to the end of the inspection period. (Section O3.2)
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Sincerely, s
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1am/ es James W. McConnick-Baraer W. McCormick-Barger,  Chief Reactor Projects Branch 7 Docket Nos.: 50-266; 50-301 cc: R. R. Grigg, President and Chief Operating Officer, WEPCO A. J. Cayia, Plant Manager B. D. Burks, P.E., Director Bureau of Field Operations Cheryl L. Parrino, Chairman Wisconsin Public Service Commission State Liaison Officer DOCUMENT NAME: P:\POIN\ pol 98003.ty To receive e copy of this document, indicate in the box "C" = Copy without attachment! enclosure "E" = Copy with attachment / enclosure "N" = No copy {
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OFFICE Rill  lt  l  l  l 1 NAME JMcC-Barger\ml(km        7
Operators were observed using reactor engineering instructions (REls), such as REl 11,
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"End of Life Coastdown," to change reactor power. The REls provided specific operational guidance and steps which were more appropriate for operating procedures. (Section O3.3)
DATE 04/so/98 OFFICIAL RECORD COPY 430 990506035[ M,o w e 7-         g L
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A deficiency existed in auxiliary operator knowledge and understanding of the operation of oil reservoirs on safety-related pumps. Licensee management indicated that training enhancements would be made to address this deficiency. (Section 04.1)
Maintenance
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Operators performed well during a special test of an emergency diesel generato Additional staff was provided for performance of the test and the test was effectively coordinated. Operators promptly identified and corrected an inadvertent service water isolation caused by an inadequate test procedure. (Section M1.1)
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Maintenance staff performed lifts of the reactor vessel head and upper intemals without incident. Procedures were followed; however a lack of strong oversight, coordination, and control in containment was noted when foreign material entered the refueling cavity pool during the upper internals lift. (Section M1.2)
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The licensee implemented improved work planning processes for on-line maintenance and refueling outages. Safety significant modifications were either completed or were scheduled for completion during upcoming outage periods. Notwithstanding these positive accomplishments, there was a large backlog of safety-related repairs and planned modifications, and some work activities were being deferred from their originally scheduled outage windows. The inspectors did not identify any examples of unsafe conditions created by the deferral of work items, but were concerned that the delays in implementing modifications would effect plant operations, such as the power transient described in Section O1.2 of this repor l The licensee provided the following backlog information: Open Corrective Maintenance items - 2069 (212 identified as high priority); Open Condition Reports - 2424; Operations ,
Workarounds - 36; Open Engineering Work Requests - 309; Open Modifications - 46 !
(Section M2.1)
. One violation was identified for a safety-related service water pump that was replaced with a work package which was inappropriate to the circumstances. An effective licensee follow-up assessment of material control concerns identified the need for some broad improvements in the control of nuclear grade parts and material. Programmatic corrective actions were planned at the end of the period; however, short term corrective actions did not receive the appropriate level of documentation and follow-up. (Section M2.2)
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. Plant staff, including design engineering personnel, continued to identify design basis
, issues. These issues were entered into the corrective action program in a prompt manner, and plant management evaluated and responded to each in an appropriste fashion. (Section E1.1)
 
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+ Reactor engineering department actions to resolve a repetitive reactor coolant pump seal leak-off alarm were not prompt or coordinated well, resulting in a long standing distraction to operators in the control room. No formal mechanism existed to disable control room annunciators or to return them to service. (Section E2.1)
. Engineering evaluations were used to disposition failures of inservice test acceptance criteria. Engineering management responded promptly by issuing informal clarification of the expectation to use the condition report and operability determination system for such failures. After additional inspector involvement, the appropriate procedures were also modified to more clearly discuss this expectation. (Section E3.1)
Plant Support There were no significant plant support findings during this inspection perio .
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Report Details  I Summary of Plant Status Unit 1 was in an end-of-life coastdown and Unit 2 was in a mid-cycle outage (U2MC23) at the start of the inspection period. Two-unit operation was achieved when Unit 2 was restarted on l February 7,1998. Unit 1 was shutdown on February 14,1998, for a refueling outage (U1R24).
 
Inspection Focus During this inspection period, the inspectors focused on the effectiveness of licensee corrective actions and completed routine inspection activities, and gathered information for a future vertical slice review of the 125-Volt direct current syste . Operations 01 Conduct of Operations 0 General Comments. Unit 2 Startup. and Main Steam System Waterhammer Inspection Scope (IP 71707)
The inspectors conducted frequent reviews of ongoing plant operations, including daily observations of control room activities and control room shift tumovers. The inspectors observed the startup of the Unit 2 reactor on February 7,199 Observations and Findinas The inspectors noted that the Unit 2 startup was conducted and controlled well, as evidenced by the use of formal communications, thorough reactor status change pre-briefings, and self checking by allindividuals involved. The operating supervisor (OS)
in charge of the reactor startup displayed good command and control of the activitie Notwithstanding the positive operator performance associated with startup activities, the inspectors were concemed by the response of operators and engineers to a waterhammer event which occurred while pre-startup evolutions were being performe The waterhammer was evidenced by a noise audible in the work control center, and by main steam system pipe movement and insulation damage in the turbine hall. After the waterhammer subsided, an engineering supervisor inspected the main steam lines for obvious damage. No damage was noted and the operators proceeded with startup. The inspectors were informed of this event only after withdrawal of control mds had .
l commenced. Through discussions with the involved individuals, the inspectors  l l concluded that the operations staff and weekend duty engineers had not developed a
! clear understanding of the type of waterhammer that had occurred (for example, slug formation versus steam void collapse), its exact location in the main steam piping, or its potential consequence other than that no visible damage had occurred and no steam ;
leaks currently existed. The inspectors were further concerr.ed that the operations '
manager and plant manager were not informed of the waterhammer prior to the unit startu I r
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! The licensee initially categorized condition report (CR) 98-0477, for the waterhammer, as j a level *B" concem, requiring a root cause evaluation. The CR was subsequently i upgraded to a level"A"(highest) concem by the plant manager. Walkdowns performed
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during the root cause evaluation of this event identified damage to energy absorbers on I
the steam pipe to the condenser dump valves. This damage was missed during the pre-startup walkdowns. A CR and operability determination were prepared for the damaged l energy absorbers after the inspectors questioned the effect of this condition on the ability l of the steam system to perform its specified functions. The energy absorbers were determined to be operable but degrade In reviewing the response of operators to this event, and to other, less significant, waterhammer events during this inspection period, the inspectors concluded that plant l
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staff were not sensitive to the potential effects of waterhammer events. This concern was discussed with the licensee staff, who stated that the inspectors' conclusion was consistent with the preliminary results of the root cause evaluation, Conclusions The Unit 2 startup was conducted well; however, operators continued with unit startup without completely understanding the cause, or identifying all of the effects, of a l waterhammer which occurred in the main steam piping during startup preparations. This was indicative of a lack of sensitivity to the potential consequences of waterhammer events. Licensee management initiated a high level root cause evaluation of the event and the operator respons .2 Control of Setpoint Adiustments and Troubleshootina Inspection Scope (IP 71707)
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The inspectors observed the conduct of operations in the control room and in the plant.
 
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Operators were observed making or directing adjustments to the moisture separator l reheater (MSR) steam flow controller and flow control valves during unit startup and l shutdown. The inspectors assessed the adequacy of administrative controls for these manipulations, Observations and Findinas l
On February 9,1998, during the Unit 2 power ascension, the inspectors observed the operating crew place the nonsafety-related MSR steam flow controller into servic Operating Procedure (OP) 1C, " Low Power Operation to Normal Power Operation,"
Revision 62, directed this activity. While performing the procedural steps, the operator in the field noted that one of the four flow control valves was not tracking with the other valves. All four valve positioners receive a common pneumatic signal from a single controller. The operators contacted instrument and controls (l&C) technicians, and the OS provided verbal direction to the I&C technicians to make the required adjustment to the valve positioner. The flow control valve performed satisfactorily after the adjustment was made. After the work was completed, the OS initiated a work order (WO) tag which documented the adjustment of the positioner. The OS told the inspectors that the use of verbal direction to authorize adjustments to balance-of-plant equipment, such as the MSR steam supply and feedwater flow control valves, was not uncommon, but that this practice was not used on safety-related systems or components, j
 
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s The inspectors subsequently asked plant management what controls existed to ensure that adjustments to safety-related equipment were adequately controlled, and what guidance existed to ensure that adjustments to balance-of plant equipment, such as the feedwater flow control valves, were evaluated for their potential impact on the primary plant prior to execution. The production planning manager and operations manager subsequently stated that a new revision to the Nuclear Power Department Procedure (NP) 8.1.1, " Work Order Processing," required that all adjustments of primary and secondary system plant equipment be controlled by the WO process prior to performance of wor The inspectors observed control room activities associated with shutting down Unit 1 on February 14,1998. The shutdown commenced from 75 percent reactor powe Step 4.2.4 of OP 3A, " Normal Power Operation To Low Power Operation," Revision 40, directed the operators to throttle steam flow to the MSRs by manually adjusting the MSR steam flow controller. This controller is located in the back panels of the control room. A reactor operator (RO) attempted to perform this step, but the controller responded in an unexpected manner. The RO requested that the OS look at the controller. The duty shift superintendent (DSS) and the duty operating supervisor (DOS) remained in front of the panels while the OS looked at the MSR controller. The RO and OS manually manipulated the controller in an unsuccessful effort to determine why it was not responding as expected. When the OS manipulated the MSR controller a second time, all four MSR flow control valves closed rapidly and unexpectedly. This created an approximately four percent primary plant power transient. The DOS left the control room and locally opened the MSR steam flow control valves, restoring the steam crossover temperature. The crew initiated CR 98-0537 to document this event, and initiated a WO for l&C to troubleshoot and repair the MSR controller. The controller was repaired and the load reduction resumed, approximately two hours later. The I&C technician determined that the OS had initiated the MSR steam flow control valve closure by de-latching two meshed gears in the controlle The inspectors considered the operator response to this transient to be adequate, but noted that the DSS assumed an active command and control role when the DOS left the control room. This action was not consistent with the expectations for DSSs specified in Operations Manual Procedure (OM) 1.1, but it did not have any direct effect on safety during this event. The inspectors noted that the power transient was initiated by operators performing informal troubleshooting on the nonsafety-related MSR steam flow controller without adequate training on the operation of the controller, and without procedural guidance or authorization. Both of these observations were discussed with the operations manager. The inspectors will continue to review the adequacy of procedures and procedure implementation under inspection follow-up item (IFI) 50-206/97020-02(DRP); 50-301/97020-02(DRP). Finally, the inspectors noted that the MSR steam flow controller was not designed for manual manipulation, but that it was manually manipulated for both startups and shutdowns. An open modification existed to replace these controllers, but the Unit 1 modification had recently been deferred (see Section M2.1 for additional discussion of maintenance and modification backlog and 1 deferrals).      ) Conclusions:
Operators were observed circumventing the licensee's work control process by verbally directing adjustments to nonsafety-related MSR steam flow control valves during a unit


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startup. Operators performing informal troubleshooting caused an unplanned closure of the MSR steam flow control valves during a unit shutdown, resulting in a four percent reactor power transient. The operator response to this minor transient was adequate, but the control room command and control roles were not consistent with the expectations in j the procedure for conduct of operation l O1.3 New Fuel Receipt inspections (IP 71707)
The inspectors observed the unloading, inspection, and storage of new fuel assemblie Three different operations crews were observed handling the new fuel. Handling operations were carefully conducted to ensure no damage occurred to the new fue Reactor engineering personnel conducted detailed and thorough inspections of each assembly to verify no damage had occurred to the fuel in transit from the manufacture The inspectors noted that Refueling Procedure 2A, " Receipt of New Fuel Assemblies,"
Revision 33, was used at the job site. Good coordination was observed between operations department and reactor engineering personne .4 Conduct of Refuelino Operations Inspection Scope (IP 71707)
The inspectors observed Unit 1 refueling outage work activities including the disassembly and removal of the reactor vessel head, reactor vessel upper internals removal, and fuel off-loading. See Section M1.2 for further discussion of refueling maintenance activitie Observations and Findinos On February 26,1998, the licensee started removing fuel from the Unit 1 reactor. The inspectors attended the pre-job briefing for fuel movement and observed the removal of the fuel from the reactor vessel and the transfer of fuel to the spent fuel pool. The inspectors had the following observations:
  . The pre-job briefing for the fuel movement was thorough and a free exchange of information existed. Individual responsib;lities (operations and health physics)
were established and supervisory command and control was clearly define * Just prior to starting fuel movement, a check was conducted to verify the requirements of refueling Technical Specification (TS) 15.3.8 had been satisfie The check concluded that the lower containment hatch could not be adequately closed. Repairs were pursued, and the TS requirements were satisfied after about a one-hour delay. A check had not been performed earlier in the outage to ensure that the requirements of the refueling TS had been complete . In preparation for fuel movement, operations personnel installed suspended lighting in the reactor vessel?The inspectors noted that the operator suspending the lighting occasionally had to move to the refueling bridge guide railing and reach into the cavity to secure the lighting. The operator braced himself along the
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cavity railing; however, the use of a safety harness would have been more
 
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B appropriate for the circumstances. The inspectors brought this to the refueling operations supervisor's attention. The supervisor stated that a safety hamess would be used in the futur . The inspectors noted that foreign material exclusion controls were not implemented for concurrent work activities on the "B" steam generator upper elevations. The location of the activities were such that anything dropped from the work areas could have fallen into the cavity and onto the core. The refueling operations supervisor noted this and notified the responsible work group supervisor. Subsequent work on exposed portions of the steam generators was conducted under foreign material exclusion control .
When the transfer cart was sent to containment to receive the first fuel assembly, it was noted that the dummy fuel assembly, used for fuel handling system surveillance checks, was stillin the upender on the cart. The transfer cart was then returned to the spent fuel pool side and the dummy fuel assembly was removed. This indicated a lack of thoroughness on the part of the previous operations crew, who conducted the fuel handling system checks, to verify that equipment was ready for fuel movemen . The first fuel assembly was placed on the transfer cart and was moved into the transfer tube and stopped. This was done to conduct containment wall radiological su veys to determine radiation dose rates. Previous experience had identified radiation streaming from the transfer tube area that affected dose rates along the containment wall. Health physics technicians identified localized areas which met the requirements for a high radiation area. Health physics supervision then determined that additionallead shielding should be placed along the affected portions of the containment wall. Due to a lack of planning, the lead shielding was not pre-staged. This led to a delay of almost three hours, while the shielding was gathered and installe .
The inspectors observed that a radiological control posting on the refueling bridge manipulator was in contact with the manipulator cabling. When the manipulator was lowered, the moving cable in contact with the posting caused the posting to move about. The inspectors alerted health physics technicians of the condition and it was immediately corrected. The inspectors discussed the occurrence with health physics management, highlighting earlier inspector observations of postings inappropriately placed on or near moving equipmen . The inspectors noted a high level of work activities ongoing in the area around the refueling cavity during the fuel movement operations. The operation of multiple cranes, workers speaking loudly, and scaffolding movement all contributed to a noisy environment within the containment. The operators involved with the fuel movement stated to the inspectors that a more controlled, quieter environment would be more conducive to focused fuel movement operation . The fuel moves were well coordinated amongst the operations staff involved, and repeat back communications were used. The refueling OS maintained good command and control over the activities, considering the working environmen _ _
 
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2 The inspectors held a meeting with plant management on February 27,1998, to convey the observations discussed above, and those discussed in Section M1.2 of this report. In addition, the inspectors related that there had been minimal management oversight noted in the plant for the activities observed. Plant management stated that these issues would be reviewed and appropriate actions would be taken. Improvement of conditions and controls for fuel movement were noted on the final day of the inspection perio Conclusions The inspectors concluded that operations personnel safely conducted and controlled fuel movements. However, severalinspector observations indicated that containment work activities lacked coordination. Minimal management oversight of containment activities was also note Operational Status of Facilities and Equipment O Reactor Coolant Pump (RCP) Lube Oil Collection System (LOCS) not in Compliance with 10 CFR Part 50. Appendix R. Reauiiements Inspection Scope (IP 71707 and IP 37551)
The inspectors reviewed the circumstances surrounding the licensee identified problems with the LOCS for both Unit 2 RCP Observations and Findinas On December 23,1997, licensee engineering personnel conducted a walkdown of the Unit 2 RCP LOCS as part of the ongoing 10 CFR Part 50, Appendix R, rebaselinbg project. The engineers determined that the installed LOCS did not fully meet the requirements of 10 CFR Part 50, Appendix R, Section Ill.O. This issue was subsequently documented in Licensee Event Report (LER) 98-004, dated February 13,199 The nature of the nonconformances included potentialleakage sites outside the LOCS boundary and potentially inadequate drain paths between the oil deflector and the leak off tray. Similar deficiencies were ascribed to the Unit 1 RCP LOCS due to its similar desig Immediate licensee compensatory measures included:
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briefing all oncoming shift personnel regarding the nonconforming condition and its potential consequences;
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modifying monthly containment surveillance checks to focus on identifying RCP oil leaks and reporting them to system engineering; and a
modifying Abnormal Operating Procedure 18 to add a note regarding the nonconforming conditio The licensee further committed to design and install the appropriate modifications in both Unit 1 and Unit 2 by the end of the next refueling outages (Spring 1999 and Fall 1998, respectively). The failure to install a RCP LOCS to collect oil from all potential pressurized and unpressurized leakage sites is a violation of 10 CFR 50, Appendix R,
 
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Section 111.0. However, this non-repetitive, licensee-identified and corrected violation was considered a non-cited violation (NCV 50-266/98003-01(DRP); 50-301/98003-01(DRP))
consistent with Section Vll.B.1 of the NRC Enforcement Polic Conclusions The RCP LOCSs were found to be in non-compliance with the requirements of 10 CFR Part 50, Appendix R, Section Ill.O. This condition was identified during the licensee's Appendix R rebaselining project. Effective compensatory actions were l implemented, and corrective actions were planne l 03 Operations Procedures and Documentation O3.1 Inadeauste Operatina Procedure for Control of Reactor Power a. Inspection Scope (IPs 71707 and IP 92901)
While performing follow-up of an unresolved item (URI), the inspectors reviewed the licensee's procedures for controlling reactor power. The URI had been opened, when inspectors observed unit operation at 100.2 percent rated thermal powe b. Observations and Findinas Point Beach Nuclear Plant Unit 1 and Unit 2 Facility Operating Licenses, Section 3.A, state that "The licensee is authorized to operate the facility at reactor core power levels not in excess of 1518.5 megawatts thermal [MWt)." During an inspection performed in January 1996, inspectors observed operation of Unit 2 at 100.2 percent of the licensed thermal power, without operator action to reduce power, and opened URI 50-206/96018-03; 50-301/96018-03 to assess whether the observed condition was a violation of NRC requirement Licensed operators informed the inspectors that unit power was controlled such that the average thermal output for an eight hour period did not exceed 1518 MWt in accordance with Operation Procedure (OP) 2A, " Normal Power OperatHn," Revision 2 Procedure OP 2A directed that operators maintain an eight hour average output of 1518 MWt in accordance with Reactor Engineering Instruction (REI) 1.0, but did not state that sustained output of more than 1518.5 MWt was unacceptable. The problem with use of an eight hour average for determining maximum allowed thermal power was that a lower than licensed power, early in the eight-hour period, would potentially allow operation at a higher than licensed power later in the eight-hour period. The inspectors considered OP 2A to be inappropriate to the circumstances and an example of a violation (VIO 50-206/98003-02a(DRP); 50-301/98003-02a(DRP)) of 10 CFR Part 50, Appendix B, Criterion V, because it created the potential of operation of the unit in a manner outside the limits of the facility licens Procedure REl 1.0, " Power Level Determination and Guidelines," Revision 20, provided guidelines for operating the units, and was invoked by OP 2A. This procedure directed that an eight hour average thermal output of 1518 MWt be maintained by matching actual power to a calculated target reactor thermal output (RTOT). The RTOT was calculated by the plant computer based upon power output to each point in time during an eight hour period. Procedure REI 1.0 specifically stated that the RTOT could potentially be as high
 
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as 1521 MWt. In add; tion, REl 1.0, paragraph 4.5, stated that sustained power operation above 100.6 percent (1527.6 MWt) was not allowed. This implied an allowable sustained power rate of up to 100.6 percent, a value in excess of the licensed limit. The inspectors considered REI 1.0 to be inappropriate to the circumstances and an example of a violation (VIO 50-206/98003-02b(DRP); 50-301/98003-02b(DRP)) of 10 CFR Part 50,
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Appendix B, Criterion V, because it created the potential of operation of the unit in a 1 manner outside the limits of the facility license.
 
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After identifying the inappropriate content of OP 2A and REI 1.0, the inspectors immediately brought the issue to the attention of senior plant management. The plant staff took prompt action to ensure that the units would not be operated at sustained
 
power levels in excess of the license limits. The inspectors did not observe any instances where operators intentionally took action to raise thermal power to a value in j
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excess of the licensed limit. Changes to OP 2A and REI 1.0, to eliminate the potential for exceeding licensed thermal output, were issued prior to the exit meeting for this inspection perio Conclusions:
The licensee procedures for operation of the two units were inappropriate in that they created the potential for sustained operation at a reactor thermal power in excess of the facility license limits. Two examples of a violation were identified. The licensee responded promptly to this inspector finding, and the procedures were revised prior to the exit meetin .2 Deficiencies in the Operatina Permit Proaram Inspection Scope (IP 71707)    l l
The inspectors reviewed the licensee's recently implemented operating permit proces This process authorizes groups other than the operations department to operate the equipment cover by the permit. One issue reviewed involved the failure of a operating l permit log designee to follow the danger tag procedur Observations and Findinas On February 13,1998, an operating permit was placed on the Unit 2 containment fan cooler system to allow for installation of test equipment. The test being performed was Operating instruction (01) 131, " Performance Test of 2HX-15D1 Containment Fan Cooler Unit 2." About an hour after a new operating crew started work, an auxiliary operator (AO) informed the control room that he was about to close the "D" containment fan motor breaker in preparation for the 01131 test. The DSS questioned this action. The AO indicated that he was being authorized to perform the action by the cognizant engineer who was signed on to the operating permit. After some discussion, the DSS allowed the AO to complete the manipulation. The inspectors, who were in the control room at the time, asked the shift supervisors if they had been informed of the 01131 activities planned for their shift. The supervisors indicated that the engineer had not directly
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notified them of any planned equipment operations, and had not obtained authorization to operate any equipment associated with Of 131.
 
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S. Patulski  -2-Qigtribution:
Procedure NP 1.9.15, " Danger Tag Procedure," Revision 5, stated, in part, that the individual signed on the operating permit log shall:
CAC (E-Mail)
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Project Mgr., NRR A. Beach J. Caldwell B. Clayton SRI Point Beach .
obtain shift supervision authorization before operating equipment controlled by an operating permit.; and l
DRP TSS DRS (2)
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Rlli PRR PUBLIC IE-01 -
as directed by shift supervision, notify or obtain authorization to operate equipment controlled by operating permit tags, while performing the wor At the request of the inspectors, the shift supervisors asked the engineer whether he was aware of the procedural requirements described above. The engineer indicated that he was not familiar with these requirements. Condition Report 98-0539 was written to document the occurrence. Management screened and categorized the occurrence as a level"D" problem (lowest priority).
Docket File-GREENS LEO (E-Mail)
 
' DOCDESK (E-Mail)
The inspectors reviewed the training given on a recent danger tag proceduro revision and the operating permit program. Maintenance staff had received recent training, and interviews indicated that the maintenance groups were aware of the expected actions and responsibilities. Likewise, operations personnel were also sufficiently trained on the procedure. However, the engineering staff had not received formal training on the revised danger tag procedure. The inspectors were informed by operators that this was not the first time that engineers had signed onto operating permits. All site engineering personnel were subsequently trained on the requirements and responsibilities associated with the operating permit progra The inspectors determined that the failure of the engineer to follow the operating permit I requirements of NP 1.9.15 constituted a violation (VIO 50-301/98003-03(DRP)) of 10 CFR Part 50, Appendix B, Criterion Conclusions An engineer failed to follow the danger tag procedure for operating permits. The inspectors determined that no training had been provided to engineers on the operating permit controls, but that more than one engineer had signed on to operating permit l Corrective actions were taken by the licensee prior to the end of the inspection perio O3.3 Use of Reactor Enaineerina instructions for Operatina the Units The inspectors noted that operators were using guidance contained in REl 11. "End of Life Coastdown," to operate Unit 1. The inspectors were concerned that REI 11 provided specific operational guidance which was more appropriately contained in an operating procedure. This concern was discussed with licensee management, who acknowledged the observatio Operator Knowledge and Performance 04.1 Auxiliary Operator Knowledae Deficiencies Reaardina Safety System Pump Oilers
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.. f Inspection Scope (IP 71707)
The inspectors reviewed the licensee's program for routine monitoring of safety system pump oil level Observations and Findinas The inspectors identified that the outer bearing oil reservoir for the Unit 1 "A" safety injection pump was positioned much lower than the corresponding oil level mark on the bearing housing. In this position, tt.e reservoir would not add make-up oil until the bearing oil level was lower than desired. The inspectors notified maintenance supervision of the condition, and it was corrected within a few hours. Although the mispositioned reservoir did not present an operability concern for the pump, the inspectors were concerned that the reservoir sppeared to have been mispositioned when refilled by an auxiliary operator (AO). Additionally, the condition had not been identified by AOs during their routine round The inspectors discussed this issue with several AOs. These discussions indicated that confusion existed among the AOs regarding the operation of the oiler reservoir Additionally, routine log sheets only required the AOs to note oillevelin the reserwir bulbs, not to evaluate the level setting relative to the pump bearing. The inspectors were also informed that recent training for the AOs on pump oil reservcdre hed not been as detailed as previous oil reservoir training. Operations management indicated that the continuing training program for AOs would be modified to include a module on the oil systems and potential problems to be aware of during rounds, Conclusions The inspectors identified a mispositioned oiler, and after follow-up, concluded that a deficiency existed in AO knowledge and understanding of the operation of oil reservoirs on safety-related pumps. Licensee management indicated that training enhancements would be made to address this deficienc Miscellaneous Operations issues 0 (Closed) LER 50-266/98-005: Missed TS Test for Control Rod Exercises. On January 21,1998, the licensee determined that the TS required bi-weekly rod exercises had not been performed on Unit 1 for over thirty days. Upon identification of the missed ,
surveillance, the licensee performed the test and achieved satisfactory results. The root !
cause of the failure to perform the test was attributed to a clerical error when data was inputted into the surveillance tracking database for the previous rod exercising surveillance. The wrong status code was inputted and, as a result, the database did not flag the need for the required surveillance. Corrective actions included a change to the computer software to reduce the risk of this type of error being repeated. A programmatic ,
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change in the work scheduling process will provide 12-week rolling schedules which will contain all required surveillances. The nonrepetitive, licensee identified and corrected, failure to perform the required surveillance is being treated as a non-cited violation
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(NCV 50-266/98003-04 (DRP)) of TS Table 15.4.1-2, item 10, consistent with Section Vll.B.1 of the NRC Enforcement Polic ..
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08.2 (Closed) URI 50-206/96018-03: 50-301/96018-03: Routine Operation at 100.2 Percent Power. This item is dispositioned in Section O3.1 of this repor . Maintenance  ,
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M1 Conduct of Maintenance M1.1 Tests and Surveillances Inspection Scope (IP 61726)
l The inspectors observed and reviewed pedormance of Point Beach Test l Procedure (PBTP)-077, " Transient Response of G-02 Replacement Govemor,"
Revision 0,
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Test PBTP-007 was performed on January 22,1998, to verify that the new govemor on emergency diesel generator G-02 would pedorm properly under accident loading l conditions. Additional control room staffing was provided for the performance of this test, I
! and individual assignments were made to all involved operators. The senior licensed operator controlling the test provided good coordination of control room activities. The
= first portion of the test was started by simultaneously removing the normal source of
; power from safety-related 4160-volt electrical distribution Bus 2A-05, and inserting a
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manual safety injection (SI) signal for the Unit 2 "A" train All systems and components worked as expected, and the inspectors observed that operators performed the necessary test verifications in the control room and the G-02 loom.
 
i The second part of the test was performed by opening and then re-closing the G-02-output breaker to 2A-05, and then verifying that G-02 and the bus loads responded properly. The results of this part of the test were also considered to be as expected, until an annunciator indicated a problem with the radioactive waste system. The control (reactor) operator responding to this annunciator identified that the service water (SW) i
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supply isolation valve for the radioactive waste system had closed.' The operators then noted that the SW supply valve to the auxiliary building air conditioning system had also closed. The operating crew concluded that the automatic isolation of the two nonsafety- ,
related SW loads had been caused by a SW isolation engineered safety feature (ESF) !
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actuation. This ESF function ensures that SW is not diverted from safety-related loads under postulated accident conditions. The operators reset the Unit 2 "A" train Si signalin accordance with PBTP-77, and restored the SW system valves to their normal position using the SW operating instruction. A four-hour report for the inadvertent ESF actuation was made in accordance with 10 CFR 50.72(b)(2)(ii). - The licensee subsequently ;
' determined that PBTP-007 was inadequate because the inadvertent ESF actuation could have been avoided by resetting the Si signal between the first and second parts of the test. The inadvertent SW isolation was of minimal safety significance, so the use of an inappropriate procedure was considered to be a non-cited violation  ,
L (NCV 50-266/98003-05(DRP); 50-301/98003-05(DRP)) of 10 CFR Part 50, Appendix B, !
Criterion V, " Instructions, Procedures, and Drawings," consistent with Section IV of the J NRC Enforcement Polic .
 
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. Conclusions Operators performed well during a special test of G-02. Additional staff was provided for performance of the test, and the test was effectively coordinated. Operators promptly identified and corrected an inadvertent SW isolation caused by an inadequate test procedur M1.2 Maintenance Refuelina Activities Inspection Scope (IP 62707 and 71707)
The inspectors observed large portions of the refueling evolutions performed by maintenance department staf Observations and Findinas The maintenance department staff was responsible for lifting the Unit i reactor vessel head and upper internals following Routine Maintenance Procedure (P.MP) 9096,
" Reactor Vessel Head Removal and Installation," Revision 16. The reactor vessel head lift was preceded by an appropriate pre-job brief during which questions were asked by all participating groups and intergroup communications were good. The evolution was performed in a coordinated and controlled manner. The procedure was followed. The inspectors did not identify any significant concerns; however, the use of at least three different procedures by the maintenance, operations, and reactor engineering departments complicated the coordination of activities associated with the head lift evolution. Licensee management acknowledged this observatio l During the pre-job brief for the upper internals lift, the responsibility for oversight and command within containment was not defined. Additional planning for potential problems could have been performed. The lift of the upper internals was performed in a deliberate and professional manner by the crane operator and lead mechanic, who followed the procedure as written. The absence of a clear chain of coordination and command was evidenced by the indecision and confusion exhibited when a thermoluminescent dosimeter (TLD) from a health physics technician fell into the refueling cavity pool during the movement of the upper internals. The TLD parts were eventually removed from the pool without incident. The cavity rail was a foreign materials exclusion area, and the TLD was taped to the technician's clothing; however, the taping method was inadequate. See Section 01.4 for discussion of inspector and licensee response to these observation Conclusions I
Maintenance staff performed lifts of the reactor vessel head and upper internals without l incident and in accordance with the procedure; a lack of strong oversight, coordination, j and control in containment was noted when foreign material entered the refueling cavity I pool during the upper internals lif l l
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        ' .M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Maintenance and Modification Backloo -
ai inspection Scope (IP 62707)
The inspectors monitored ongoing outage planning activities to ensure that TS limiting conditions for operation were satisfied, to ensure that risk assessment considerations ;
were included in the scheduling of maintenance activities, and to ensure that safety !
significant repairs and modifications were implemented in a timely manne Observations and Findinas The licensee implemented a new outage planning process for U1R24. This process resulted in improvements in activity planning and scheduling prior to commencing the outage. A 12-week rolling work schedule was also initiated during this assessment period. Both of these initiatives provided mechanisms for increased use of risk
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assessment in the scheduling and performance of maintenance activities. The new planning processes required the completion of modification and repair work packages much earlier than in previous outages. Early development of work packages allowed for better resource loading determinations and better estimates of work duration, both of which facilitated the proper use of risk assessment in establishing plant conditions and controlling equipment availabilit ' The inspectors reviewed outage review committee meeting minutes to determine which safety-related corrective maintenance and modification work items were being performed during U2MC23 and U1R24. Severalimportant work items were performed or scheduled for performance, including auxiliary feedwater pump low suction pressure protection system modifications, main control board wire separation modifications, and SW pipe replacement and modifications. The completion rate for items in the U2MC23 schedule was good. The inspectors did not identify any examples where time-sensitive, safety-critical repairs or modifications with regulatory commitment dates were removed from U1R24; however, several work items for safety-related repairs and modifications had been removed from U1R24. Examples of deferred items included replacement of auxiliary feedwater check valves (potential waterhammer issue), replacement of SI -
accumulator level transmitters (inaccurate control room indication issue), and portions of the main control board wire separation modification (licensing basis conformance issue).
 
The nonsafety-related modification to the MSR steam flow controllers was also deferred from U1R24 (see Section O1.2). These work items were delayed or deferred because the engineering, planning, and maintenance capabilities of the facility prevented their completion during the planned outage period. Deferred items which could not be performed with the unit on-line were scheduled for future outages. Deferred items which could be performed with the unit on-line were not given scheduled completion dates. The production planning manager informed the inspectors that there was currently no method for determining the impact of deferred work on future outages, or for determining when work delayed for performance on line would actusily be performe '
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l The licensee provided the inspectors the following information on backlogs, effective February 20,1998:
Open Corrective Maintenance items: 2069 (212 identified as high priority)
Open Condition Reports:  2424 Operations Workarounds:  36 Open Engineering Work Requests: 309 Open Modifications:  465 Conclusions The licensee implemented improved work planning processes for on-line maintenance and refueling outages. Safety significant modifications were completed or were scheduled for completion during upcoming outage periods. Notwithstanding these positive accomplishments, there was a large backlog of safety-related repairs and planned modifications, and some work activities were being deferred from their originally scheduled outage windows. The inspectors did not identify any examples of unsafe conditions created by the deferral of work items, but were concerned that the delays in implementing modifications could affect plant operations, such as the power transient described in Section 01.2 of this repor M2.2 Service Water Pump Modification Inspection Scope (IPs 62707. 61726. and 37551)    ,
l The "A" SW pump (P-32A) was rebuilt during the inspection period. The inspectors l reviewed the circumstances leading up to the pump replacement, observed the replacement of the pump and surveillance testing of the pump, and assessed the technical evaluations associated with out-of-tolerance test and inspection result Observations and Findinas Point Beach has six two-stage " wet-pit" type SW pumps. These pumps are subject to high vibration because of their design and service environment. Three pumps are required to meet accident analysis loads, assuming loss of emergency power to the other three pumps. The TSs allow one pump to be out-of-service for up to seven days, an allowed outage time which is longer than that provided for (72 hours) in NUREG 1431,
" Standardized TSs for Westinghouse Plants." The extended outage time is based upon the physicallimitations (pump design and rigging considerations) which impact pump replacemen Risk Assessment in Schedulina Pump Repair l The P-32A pump was found to be in the alert range for vibration on September 30,1997.
 
l The licensee subsequently placed P-32A on an increased frequency of vibration analysis, l implemented special operating restrictions for the pump, and ordered replacement parts I to support a pump replacement. The pump replacement included installation of modified parts and troubleshooting of the cause of the vibration. The P-32A vibration was reduced to below the alert range when the operating Unit 2 circulating water pump was secured during the Unit 2 shutdown in November 1997. The licensee subsequently noted that
 
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forebay water level, and hence net positive suction head for the SW pumps, increased when circulating water pumps were stopped.
 
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When pump vibration went below the alert range, the pump replacement was postponed from December 1997, when only one unit was operating, to the first week of February 1998, when two units were scheduled to be operating. While either condition would have been allowed under T/Ss, performance of the pump replacement with a single unit operating would have been preferable from a risk perspectiv Vibration data for P-32A obtained on January 26,1998, exceeded the allowed operability value by approximately 25 percent after a Unit 2 circulating water pump was started. The service water pump was promptly declared inoperable. Plant engineering and operating staff recognized that scheduling a unit startup prior to repairing a known problem with a SW pump war potentially inappropriate, and initiated CR 98-0296 on January 26,1998, to document this conclusion. Plant management recognized the significance of this issue, and required a root cause evaluation and establishment of effective corrective actions and lessons-learne The inspectors considered the decision, in November 1997, to postpone repair of P-32A until two units were operating to have been non-conservstive, but considered the licensee's January 1998 documentation and follow-up to this issue to have been appropriat Performance of Work and Procedure Adeauacy Work Order (WO) 9711936001 provided authorization for performance of the P-32A i replacement. This work order was supported by three " Work Plans," one each for mechanical work, electrical work, and pump balancing. Work started on January 28, 1998. The P-32A discharge check valve, SW 32A, was opened and inspected using a routine maintenance procedure while the pump was out-of-service. The inspectors considered the overall knowledge and performance of the mechanics involved in the P-32A and SW-32A work to have been good. The level of detail in the procedural steps of the SW 32A procedure and P-32A work plans was adequate. The inspectors identified severalissues associated with use of the P-32A work plans. These issues were discussed with plant management and are described belo Desian Control and Condition Reportina: The replacement pump was fitted with an inlet basket strainer with two-inch by two-inch openings, but the openings on the removed pump's inlet basket strainer were only one-inch by one-inch. The mechanics and component engineer involved with pump replacement had not documented this discrepancy on a CR or within the WO work plan. The work plan did not contain any descriptive information for the strainer, so it was not readily apparent which strainer size was correct. The inspectors obtained and reviewed the controlled vendor drawing for the SW pumps, and determined that it did not contain sufficient detail to determine which, if either, strainer was correct. After the inspectors identified this issue, the licensee initiated CR 98-0357 to document the difference in strainers. The licensee determined that Spare Parts Equivalency Evaluation Document 96-050 supported use of the replacement strainer. The licensee canceled Technical Evaluation 92-64, Revision 1, under which the strainer with one-inch by one-inch openings had been purchased. The inspectors also noted during the reassembly of the pump that two shims were installed to l
eliminate axial misalignment between the pump and pump motor. However, the location
 
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l and size of these shims were not recorded in the work package. The absence of this information from the design record could affect future out-of service durations for the Pum Control of Procedures: The inspectors noted that the WO work plans for the P-32A replacement were not marked as controlled documents and were not provided with revision numbers. The inspectors also identified that the date on each WO work plan page indicated when it was printed, not when the document was developed or revise ,
Control and Trackina of Material: The inspectors noted that the WO package did not include any drawings depicting what the replacement pump assembly should look like, what all the parts of the pump were, and where all replacement parts should be use There was a comprehensive bill of material at the job site, but it was not controlled as part of the WO or as part of any other controlled system. The WO work plans did contain complete lists of replacement parts, but these lists referenced material control numbers l which, in some cases, could not be readily traced to the parts being used. The l inspectors also noted that mechanics were not specifically documenting that items obtained for the job were actually being used in the replacement of the pump. The inspectors noted that the use of multiple, and not completely cross-referenced, material identification records created a human factors problem for an independent party or i supervisor trying to certify the completion of work. The inspectors observed that the lack l of detail in the work package documentation was being compensated for by the direct involvement of the component engineer in the maintenance activity. This engineer was l providing information to the mechanics regarding the fit-up and assembly of the pum i While the inspectors considered the engineer's knowledge level and level of involvement to be positive, the lack of formality in controlling the pump design basis (materials and configuration) was a concem. The licensee responded to the inspectors' concerns by performing maintenance department and quality assurance reviews of the P-32A replacement and a sampling of other WO work plan safety-related maintenance activitie No operability issues were identified during these reviews, but CRs 98-0344,-0348, 1-0359, -0361, -0391, -0396, -0453, -0456, -0467, -0506, and -0524 were written to I identify examples of concerns with the adequacy of WO work plan instructions and l material control issues. All identified items were being addressed through the licensee's corrective action program. The inspectors determined that no significant regulatory concerns were contained in these CR The inspectors discussed the above concerns with licensee management. Management acknowledged that the replacement of the safety-related service water pump should have been performed using a procedure, based upon the procedural requirements of NP 1.2.2,
" Technical, Procedure Classification, Review, and Approval," Revision 3. The licensee believed that use of a procedure would have addressed many of the inspectors concern The use of a work instruction which did not provide current drawings to support use of a revised pump configuration, did not include a comprehensive list of materials for assembling the replacement and reused pump components, and did not provide for positive identification of the nuclear quality grade components actually used in the final pump assembly was a violation (VIO 50-206/98003-06(DRP); 50-301/98003-06(DRP)) of l 10 CFR Part 50, Appendix B, Criterion V," Instructions, Procedures, and Drawings."
 
The licensee initiated a formal root cause evaluation of the material controlissues identified by the inspectors and by the subsequent quality assurance assessments. A month after the issues of work package content and material controls were identified, the
 
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inspectors reviewed the status of corrective actions for the CRs listed above and identified that no immediate corrective actions were documented. This was of concem because a refueling outage and other safety-related activities, such as a major ,
maintenance outage for the G-01 emergency diesel generator, were underway. This '
concem was discussed with maintenance department management, who indicated that
; initial communications to maintenance staff had been made, but that follow-up actions to ensure these communications had been effective were also appropriat )
Surveillance Testina and Technical Evaluations The inspectors observed testing associated with Inservice Test Procedure (IT) 07A, IT 078, and IT 07C. These tests were specified as post-maintenance testing for the replacement of Service Water Pump P-32A and the repair of discharge Check Valve SW-32A. The inspectors reviewed the three ITs and did not identify any significant
, issues. The test results for IT 07A were satisfactory, but the flows for P-32B and P-32C,
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when measured by IT 07B and IT 07C, respectively, were out-of-tolerance on the high
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side. The licensee completed operability determinations (ODs) for these failed test
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results and attributed the indicated high flows to improvements in the performance of SW-32A (less back leakage with P-32A secured). The inspectors reviewed CRs 98-0349, 98-0350,98-0362, and 98-0457, which documented the failed tests and the SW-32A improvements. The inspectors considered the licensee ODs to be technically accurate, but lacking in support information. The inspectors had to obtain additional information on ;
the service water hydraulic model and the inservice test requirements for the valves in !
order to independently confirm the conclusions reached by the licensee staff, Conclusions A safety-related SW pump was replaced without adequate documentation in the work l package. The inspectors were also concerned by aspects of the material control practices used. An effective licensee follow-up assessment of the inspectors' concems identified the need for some broad improvements in the control of nuclear grade parts and material. Programmatic corrective actions were planned at the end of the period; however, short-term corrective actions did not receive the appropriate level of attention and follow-up. A violation was identified for an inadequate work instruction that failed to provide appropriate material control l I
M8 Miscellaneous Maintenance issues    l
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M8.1 (Closed) LER 50-266/98-006-00: Unanticipated Partial SW System isolation During A  l l
Special Test. This item is discussed in Section M1.1 of this inspection repor l Ill. Enaineen'n2 E1 Conduct of Engineering E1.1 ' identification of Desion Basis issues and Nonconformances The inspectors observed that plant staff, ir4cluding the design engineering group, continued to identify design basis issues. These issues were entered into the 21    ,
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corrective action program in a prompt manner, and plant management evaluated and responded to each in an appropriate fashio E2 Engineering Support of Facilities and Equipment E2.1 Unit 2 RCP Seal Return Flow Indication Spikina Inspection Scope (IPs 71707 and IP 37551)
The inspectors reviewed the circumstances surrounding the cause of a frequent main control room annunciator alarm for Unit 2 "A" RCP seal water flo Observations and Findinas During main control room observations, the inspectors noted that the " Unit 2 'A' RCP seal l water flow low /high" alarm frequently activated and then cleared immediately. The relevant chart recorder indicated a spike (low) of about one second in duration followed by flow retuming to normal. On one occasion, the inspectors observed this alarm activate as many as 10 times in a 25-minute period. Based upon the observed operator response, the inspectors concluded that this alarm had become a distraction to the operators in the control roo The inspectors held a meeting with engineering supervision and staff to learn what efforts had been taken to identify and correct the cause of the frequent alarm. Reactor and systems engineering staff provided the inspectors with several potential scenarios that could cause the detected flow spike and initiate an alarm. The staff also told the inspectors that the manufacturer of the RCP seals believed the problem was in the instrumentation (not a physical problem with the seals). Based upon this assessment, attempts had been made to adjust instrumentation dampening circuits to eliminate the alarm, but this had not been effectiv I1 During the course of the meeting, it became clear to the inspectors that the resolution
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management of the problem was not well controlled and no one had been assigned single-point responsibility for the matter. It was also evident that the involved engineers were not sensitive to the distraction created in the control room by the frequent alar Engineering supervision indicated that an " owner" for the issue would be assigned and a responsible supervisor would monitor the resolution of the issue. The inspectors were ,
told that operations department managers had discussed the repetitive alarm with engineering department managers on several occasions, but had not been demanding enough to ensure an adequate engineering respons During continued follow-up of this issue, the inspectors noted that a midnight control room shift had disabled the annunciator in question. When questioned about the disabling of the alarm, control room supervisors and control operators indicated that the decision was j made because the alarm had became a nuisance and was a distraction from on-going -
Unit 1 activities. The inspectors noticed that subsequent control room crews placed the annunciator back in-service. A review by the inspectors revealed that no formal program existed for disabling control room annunciators or tracking their status. Compensatory l
measures were informally discussed by operations supervisors and control operators prior to disabling the annunciator. The alarms were logged in the unit specific logbook as being out-of-service. Operations management acknowledged that they were aware that
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l r w cl no formal program existed. Following a discussion between the inspectors and the operations manager, interim guidance was provided to the operating crews to define expectations for disabling annunciator Toward the end of the inspection period, the gas stripper system was retumed to service l and the alarm spiking no longer occurred. The technical explanation of the effect the gas stripper had on the RCP seal flow had not been determine Conclusions The inspectors concluded that reactor engineering department actions to resolve a repetitive RCP sealleak-off alarm were not prompt or coordinated well. The lack of a prompt, coordinated response resulted in a long-standing distraction to operators in the control room. The inspectors also noted that no formal mechanism existed to disable control room annunciators or return them to servic E3 Engineering Procedures and Documentation E3.1 Use of Enaineerina Evaluations Versus Operability Determinations Followina 1SI-850 Valve Testina Inspection Scope (IP 37551)
The inspectors reviewed the licensap's use of engineering evaluations to determine operability following inservice testing (IS f safety system pumps and valve Observations and Findinos On January 16,1998, the licensee conducted routine quarterly IST of the Unit 1 safety injection recirculation sump valves. Following the performance of the Train A valve (1SI-850A) test, it was noted that the times to open the valves were slower than the specified acceptance criteria. The operations supervisor declared the valve out-of-service, and requested an engineering evaluation be performed to address the issu The evaluation was subsequently performed, and the valve was declared back-in-servic The inspectors observed the valve being retumed to service. The inspectors questioned why an engineering evaluation had been performed when the basis statement of TS 15.4.2.8 stated that operability determinations were used for failures to meet IST acceptance criteria. The control room supervisors indicated that the use of an engineering evaluation had been the acceptable past practice for such situations. The inspectors discussed this issue with engineering departmental management, who agreed that an operability determination should have been used. An operability determination
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was then performed, and the valve was placed back-in-service prior to exceeding the TS allowed outage time.
 
I The inspectors noted that the use of an engineering evaluation for the return-to-service of components following inservice tests had been a routine practice in the past. Following this occurrence, the engineering manager issued an electronic memorandum to all engineering department staff to alert them to the proper method of dispositioning
 
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..      1 acceptance criteria discrepancies. The memorandum stated that a condition report would be written and an operability determination would be developed when equipment failed to meet IST acceptance criten The inspectors also noted that recent revisions to operability determination procedure (NP 5.3.7) did not succinctly state this current management expectation. This was discussed with the IST coordinating engineer, who subsequently revised the procedure to more clearly discuss the proper use of engineering evaluations and operability determinations following IST surveillance Conclusions The inspectors identified a potentially inappropriate practice of using engineering evaluations to disposition failures to satisfy IST acceptance criteria. Engineering management responded promptly to this observation by issuing an informal clarification of the expectation for using the CR and operability determination systems. After additional inspector involvement, the appropriate procedures were also modified to more clearly discuss this expectatio E8 Miscellaneous Engineering issues E8.1 (Closed) Unresolved item (URI) 50-266/97006-06(DRP): 50-301/97006-06(DRP):
Adequacy of Twice Per Shift Fire Rounds for Degraded 10 CFR Part 50, Appendix R, Areas. The inspectors reviewed the licensee's current licensing basis for 10 CFR Part 50, Appendix R, programs. The licensee's Fire Protection Evaluation Report detailed the compensatory actions to be taken for various fire condition action levels and referenced safe shutdown areas. The compensatory measures to be taken when areas are degraded was defined in OM 3.27," Control of Fire Protection and Appendix R Safe Shutdown Equipment," Revision 6. The twice por shift fire rounds were outlined in this procedure. The inspectors determined that the licensee was implementing the fire rounds in accordance with the current licensing basis. The inspectors also noted that the licensee had revisited this issue in response to NRC Information Notice 97-048,
" inadequate or inappropriate Interim Fire Protection Compensatory Measures." The inspectors had no further concerns regarding this matte E8.2 (Closed) URI 50-266/96012-08(DRP): 50-301/96012-08(DRP): Pressurizer Safety Valve Setpoint Too High. This item was updated in Inspection Report 50-266/97020(DRP);
50-301/97020(DRP), Section E8.1. That update stated that the corrective actions, tests reports, and installation of Unit 2 safety valves were adequate. However, the inspectors had remaining questions regarding Unit 1 valves. The two questions involved the completeness of the original operability determination in addressing temperature changes and their effect on Unit 1 valves, and setpoint drift and its impact. The update also identified that the event which was reported under 10 CFR 50.72 requirements but was not followed up with a written LER. The LER (50-266/96-014) was subsequently submitted on October 24,199 Following a discussion with the inspectors at the time of the aforementioned inspection report, the licensee conducted further evaluations of the Unit 1 safety valves and amended the original operability determination. The results of the analysis indicated that at lower ambient temperatures the valve lift point would increase by 2.01 percent
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(2542.1 pounds per square inch gauge). This was within the ASME Section XI limit of l
 
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103 percent of the nameplate (2559.6 pounds per square inch). Analysis of the setpoint drift effects resulted in a minimal increase in the lift setpoint over a 36-month period (frequency of valve testing).
 
The initiating condition associated with this issue was an inappropriate test temperature used in testing safety-related components. This nonrepetitive, licensee-identified and corrected violation is being treated as a non-cited violation (NCV 50-266/98003-07(DRP);
50-301/98003-07(DRP)) of 10 CFR Part 50, Appendix B, Criterion XI, " Test Control,"
consistent with Section Vll.B.1 of the NRC Enforcement Polic E (Closed) LER 50-266/96-014: Pressurizer Safety Valve Lift Setpoint Out of Tolerance Due to Temperature Effects. This item is discussed in Section E8.2 abov E (Closed) URI 50-266/95004-05(DRP): 50-301/95004-05(DRP): Adequacy of Design Modification. This item dealt with the quality of engineering work associated with a design modification implemented in 1994. The modification was subsequently removed when the licensee determined that it was ineffective. The inspectors determined that the design work associated with this modification was not of a high quality, but concluded that further review of this issue served no purpose since the quality of engineering work has been the subject of significant er.forcement actions subsequent to the 1995 identification of this issu IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R General Comments NRC Inspection Procedure 71750 was used in the performance of an inspection of the plant support area. In general, the inspectors found the auxiliary building to be appropriately posted and controlled for radiological hazards. Workers within the auxiliary building were observed wearing required dosimeters and following good radiation worker practices. However, the inspectors had concerns regarding the performance of the health physics organization during refueling operations. These observations are contained in Sections 01.4 and M1.2 of this repor V. Management Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on March 5,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
 
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PARTIAL LIST OF PERSONS CONTACTED
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Licensee Wisconsin Electric Power Company l S. A. Patuiski, Site Vice President
- A. J. Cayia, Plant Manager M. E. Reddemann, Quality Assurance Manager R. G. Mende, Operations Manager l  W. B. Fromm, Maintenance Manager
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J, G. Schwaitzer, Site Engineering Manager R. P. Farrell, Health Physics Manager D. F. Johnson, Regulatory Services and Licensing Manager
 
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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering -
IP 40500: Effectiveness of Licensee Controls in identifying, Resolving, and Preventing Problems l IP 61726: Surveillance Observations
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IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92901: Follow-up of Operations issues IP 92903: Follow-up of Engineering issues ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-266/98003-01(DRP) NCV Inadequate Oil Collection System 50-301/98003-01(DRP)
50-266/98003-02a(DRP) VIO Inadequate Thermal Power Procedure 50-301/98003-02a(DRP)
50-266/98003-02b(DRP) VIO Inadequate Thermal Power Procedure 50-301/98003-02b(DRP)    j 50-301/98003-03(DRP) VIO Operating Permit Procedure Violation 50-266/98003-04(DRP) NCV Missed Surveillance 50-266/98003-05(DRP) NCV Inadequate Test Procedure 50-301/98003-05(DRP)
50-266/98003-06(DRP) VIO Inadequate Maintenance Procedure for P-32A 50-301/98003-06(DRP)
50-266/98003-07(DRP) NCV inadequate Test Controls 50-301/98003-07(DRP)
Closed 50-266/99005  LER Missed Control Rod Surveillance 50-266/96018-03(DRP) URI Routine Operation at 100.2 Percent Power 50-301/96018-03(DRP)
50-266/98006  LER Service Water isolation During Special Test 50-266/97006-06(DRP) URI Adequacy of Fire Rounds 50-301/97006-06(DRP)
 
T. :;W f. {
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i f  ITEMS OPENED, CLOSED, AND DISCUSSED (Continued)
Closed (Continued)
50-266/96012-08(DRP) URI Pressurizer Safety Valve Setpoints 50-301/96012-08(DRP)
50-266/96014 LER Pressurizer Safety Valve Setpoints 50-266/95004-05(DRP) URI Adequacy of Design Modi'ication 50-301/95004-05(DRP)
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LIST OF ACRONYMS USED IN POINT BEACH REPORTS i
AC Alternating Current AFW Auxiliary Feedwater AO Auxiliary Operator ASME American Society of Mechanical Engineers CFR Code of Federal Regulations CLB Current Licensing Basis CR Condition Report DRP Division of Reactor Projects DSS Duty Shift Superintendent ECCS Emergency Core Cooling System ESF Engineered Safety Feature EP Emergency Planning FSAR Final Safety Analysis Report l&C instrument and Control IFl inspection Follow-up item IP inspection Procedure IPE Individual Plant Evaluation IR Inspection Report ILRT Integrated Leak Rate Test IST Inservice Testing IT In-service Test Procedure LCO Limiting Condition for Operation LER Licensee Event Report LOCS Lube Oil Collection System MSR Moisture Separator Reheater MWt Megawatt Thermal NCV Non-Cited Violation NDE Non-Destructive Examination NP Nuclear Power Department Procedure NRC Nuclear Regulatory Commission OD Operability Determination 01 Operating Instruction OM Operations Manual OOS Out-of-Service OP Operating Procedure ORT Operations Refueling Test OS Operating Supervisor PASS Post-accident Sampling System PBTP Point Beach Test Procedure PDR Public Document Room OA Quality Assurance RCP Reactor Coolant Pump RCS Reactor Coolant System REI Reactor Engineering Instruction RHR Residual Heat Removal l RMP Routine Maintenance Procedure l RP Radiation Protection i RWST Refueling Water Storage Tank l    29
 
:p ' " '    1 SER Safety Evaluation Report SFP Spent Fuel Pool S Service Water TDAFW Turbine Driven Auxiliary Feedwater TLD Thermoluminescent Dosimeter TS Technical Specification TS Technical Specification Test URI Unresolved item
- VIO Violation .
VNCR Control Room Ventilation
 
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Latest revision as of 04:41, 2 February 2022

Ack Receipt of Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-266/98-03 & 50-301/98-03 Issued on 980321.Corrective Actions Will Be Examined During Future Inspections
ML20217P600
Person / Time
Site: Point Beach  NextEra Energy icon.png
Issue date: 04/30/1998
From: Mccormickbarge
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To: Patulski S
WISCONSIN ELECTRIC POWER CO.
References
50-266-98-03, 50-266-98-3, 50-301-98-03, 50-301-98-3, NUDOCS 9805060358
Download: ML20217P600 (2)
v • d • e


Text

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@p April 30, 1998 Mr. S. A. Patulski Site Vice President Point Beach Nuclear Plant Wisconsin Electric Power Company 6610 Nuclear Road Two Rivers, Wisconsin 54241 SUBJECT: NOTICE OF VIOLATION (NRC INSPECTION REPORT NO. 50-266/98003(DRP);

50-301/98003(DRP))

Dear Mr. Patuiski:

This will acknowledge receipt of your letter dated April 20,1998, in response to our letter dated March 21,1998, transmitting a Notice of Violation associated with Inspection Report No. 50-266/98003(DRP); 50-301/98003(DRP). We have reviewed your corrective actions and have no further questions at this time. These corrective actions will be examined during future inspections.

Sincerely, s

1am/ es James W. McConnick-Baraer W. McCormick-Barger, Chief Reactor Projects Branch 7 Docket Nos.: 50-266; 50-301 cc: R. R. Grigg, President and Chief Operating Officer, WEPCO A. J. Cayia, Plant Manager B. D. Burks, P.E., Director Bureau of Field Operations Cheryl L. Parrino, Chairman Wisconsin Public Service Commission State Liaison Officer DOCUMENT NAME: P:\POIN\ pol 98003.ty To receive e copy of this document, indicate in the box "C" = Copy without attachment! enclosure "E" = Copy with attachment / enclosure "N" = No copy {

OFFICE Rill lt l l l 1 NAME JMcC-Barger\ml(km 7

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DATE 04/so/98 OFFICIAL RECORD COPY 430 990506035[ M,o w e 7- g L

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S. Patulski -2-Qigtribution:

CAC (E-Mail)

Project Mgr., NRR A. Beach J. Caldwell B. Clayton SRI Point Beach .

DRP TSS DRS (2)

Rlli PRR PUBLIC IE-01 -

Docket File-GREENS LEO (E-Mail)

' DOCDESK (E-Mail)

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