IR 05000266/1998021
| ML20199H569 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 01/15/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20199H555 | List: |
| References | |
| 50-266-98-21, 50-301-98-21, NUDOCS 9901250240 | |
| Download: ML20199H569 (31) | |
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U.S. NUCLEAR REGULATORY COMMISSION !
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Docket Nos: 50-266; 50-301
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Report No: 50-266/98021(DRP); 50-301/98021(DRP)
Licensee: Wisconsin Electric Power Company ,
Facility: Point Beach Nuclear Plant, Units 1 & 2 l
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Location: 6610 Nuclear Road l Two Rivers, WI 54241 Dates: November 21,1998, through January 4,1999
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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: B. Burgess, Chief i Reactor Projects Branch 7 l
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l EXECUTIVE SUMMARY Point Beach Nuclear Plant, Units 1 & 2 Inspection Report 50-266/98021(DRP); 50-301/98021(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week inspection period by the resident inspector .
1 Operations
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l The inspectors found the licensee's receipt, inspection, and storage of new fuel assemblies to be well coordinated and properly implemented. (Section 01.1)
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Overall, although the planning for the Unit 2 cycle 23 refueling outage improved from that of previous outages, the licensee did not meet its own pre-outage planning milestones, resulting in the potential for poor quality outage work documents and unnecessary worker radiation exposure. In addition, this pre-outage plan l implementation problem reduced the time avaliable to the licensee to perform risk and safety assessments of the scheduled outage work and to identify potential Technical Specification conflicts, instead placing those burdens on control room operator (Section 01.2)
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Operators safely shut down Unit 2 for the refueling outage. However, poor material condition, unresolved operator workarounds, and a lack of procedures resulted in a distraction to operators and required operator intervention during a critical and complex evolution. (Section 01.3)
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The inspectors verified that the licensee had completed the cold weather preparation 1
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checklist; however, there was no checklist item or procedure for ensuring that ventilation systems used to protect safety-related equipment from cold weather were maintained in
! the proper configuration after performance of the checklist. Additionally, at the end of the inspection period, the licensee identified problems with maintaining the containment facade freeze protection equipment operational after the checklist was complete (Section O2.1)
. The inspectors' observations of the Unit 2 reactor vessel head lift indicated the i continued need for licensee focus on conservative plant operation and proper procedure usage during major refueling activities. These observations and those documented in previous inspection reports reinforce the inspectors' concerns with some operators'
understanding of procedure adherence requirements and with the unclear guidance l contained in OM 1.4 regarding these requirements. Also, plant staff did not ensure adequate coordination of two procedures being used in paral!el during the leak check l
inspection of the cavity-to-vessel seat ring during cavity flood-up. (Section O3.1)
. Operators responded appropriately during the November 14,1998, rapid reactor down i power and removal from service of the Unit 1 "A" steam generator feedwater pump l because of an outboard pump bearing failure. The inspectors identified concerns
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regarding the potential for inconsistent operator transient response and abnormal operating procedure use and implementation. (Section O4.1)
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The quality verification department did not identify any issues during Unit 2 shutdown observations, including those issues identified by the inspectors. This lack of issues called into question the effectiveness of the quality verification department's operations-related efforts. (Section O7.1)
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Deficiencies existed in the licensee's Nuclear Regulatory Commission commitment management program similar to problems identified by the inspectors in 199 (Section 07.2)
Maintenance
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The licensee's use of a work-week coordinator facilitated the completion of the "B" motor-driven auxiliary feedwater pump outage; thereby, minimizing equipment out-of-service time. The mairtenance activities were conducted in an acceptable manner, using the appropriate paperwork. (Section M1.1)
The repairs of the Unit 1 "A" component cooling water pump were conducted in a manner commensurate with the safety significance of the job. Proper controls were used to minimize potentialimpact on the remaining operable Unit 1 *B" component cooling water pump. The inspectors concluded that the long-standing component cooling water pump seat material condition / design issue had not yet been resolved, which had resulted in a failure of safety-related equipment and the continued existence of an operator workaround. (Section M1.2)
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Station management displayed conservative, risk-based decision-making regarding the approval and installation of a Unit 2 safety injection system modification. The modification was intended to address the long-standing need to use manual actions after an accident to align the safety injection system for the recirculation phase. The inspectors identified no concerns with the safety evaluation and installation work plans for the modification. (Section E2.1)
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The component cooling water system engineer's knowledge of assigned system fundamental characteristics was adequate, even though he was only recently given responsibility for the system. The inspectors identified the lack of controls to specifically limit the minimum component cooling water system operating temperature to within its design value. (Section E4.1)
. The licensee performed an assessment of the nuclear fuel function area relying on source documents and using offsite technical expertise. The inspectors concluded that the assessment of corrective action content appeared adequate but that the licensee failed to recognize that completing those actions in a timely manner was also importan (Section E7.1)
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The licensee appropriately lowered the Unit 2 refueling outage 25 personnel exposure goal to better monitor and control radiation worker exposure. (Gection R1.1)
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Report Details Summary of Plant Status Unit 1 began the inspection penad at 50 percent power because of problems with the "A" steam !
generator feed pump. On November 22,1998, Unit 1 power was reduced to 13 percent to '
repair a high pressure turbine exhaust sensing line steam leak and was retumed to 50 percent i later that same day. The "A" steam generator feedwater pump was returned to service on
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November 28 and Unit i reached 100 percent power on November 29. On December 2, power was reduced to 95 percent because of excessive vibration of the "A" steam generator feedwater pump suction piping and attached smaller bore piping. Power was returned to 100 percent on December 4, following installation of vibration dampening material on the suction piping, and I remained there through the end of the inspection perio )
Unit 2 began the inspection period at 75 percent power, in an end-of-life coast down to a scheduled December 5 refue, ling outage. On December 2, power was reduced to 50 percent to go into a single steam generator feedwater pump alignment for the remainder of cycle operation. Unit 2 shut down on December 5 for the outage. The inspection period ended with Unit 2 in the outag . Operations 01 Conduct of Operations 01.1 New Fuel Receipt inspections Inspection Scope (Inspection Procedures (IPs) 71707 & 60705) ,
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The inspectors observed the unloading, inspection, and storage of new fuel assemblies i in preparation for the Unit 2 refueling outage number 23 (U2R23). j Observations and Findinas l Two operations crews were observed handling the new fuel assemblies at different times. Handling operations were carefully conducted to ensure no damage occurred to the new fuel. Reactor engineering personnel conducted detailed and thorough inspections of each new fuel assembly to verify no damage had occurred in transit from the manufacturer. The inspectors noted that Refueling Procedures 2A, " Receipt of New Fuel Assemblies," Revision 35, and 2C, "New Fuel and Fuel insert inspection,"
Revision 18, were used at the job site. Good coordination was exhibited among operations, radiation protection, and reactor engineering personnel. The inspectors also observed that foreign material exclusion practices were implemented in accordance with station procedure Condition Report (CR) 97-4123 documented that with the enrichments used for the 18-month fuel assemblies, suberiticality in the new fuel vault could not be assured under all postulated conditions without the new fuct assemblies stored in the vault in a
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checkerboard pattern. The inspectors verified that the assemblies were being loaded in :
a checkerboard pattem as required by the corrective action for CR 97-412 l l Conclusions
The inspectors found the licensee's receipt, inspection, and storage of new fuel assemblies to be well coordinated and properly implemente .2 Preparations for Unit 2 Refuelina Outaae Insoection Scope (IPs 71707 & 60705)
l Th inspectors reviewed U2R23 preparations and the status of related action Observations and Findinas :
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The outage was scheduled to begin on December 5,1998, with a duration of 68 day Three major projects were planned: core baffle former bolt inspection / replacement, main control board wire separation, and upgrading of both low pressure turbine Additionally, a 10-year inservice inspection of the reactor vessel (RV) was schedule l The inspectors attended an outage preparation meeting on November 18 (16 days prior to start of U2R23). The status of licensee preparations was as follows: ,
. Total Work Orders = 1501 Total Work Orders Ready for Work = 963 '
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. Total Modifications = 47 Total Modifications Released for Work = 37
. Operations Procedures U2R23 Related Revisions = 380 Operations Procedures U2R23 Revisions Completed = 264
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Total U2R23 Equipment Tagouts = 350 U2R23 Equipment Tagouts Approved = 24 As of the meeting, a total of 62 out of 95 pre-outage milestones had been completed (36 of 62, or 58 percent, were past their due date) with 33 milestones remaining and 15 of those overdue. Revision 0 of the U2R23 outage schedule was not planned to be completed until December 4,199 i Not meeting these milestones resulted in there being insufficient time for the licensee to l adequately review the outage schedule in its final form prior to implementation. By l doing so, the licensee minimized their opportunities for conducting risk and safety .
assessments of planned activities and for identifying potential Technical Specification l (T/S) conflicts and methods to shorten safety-related equipment out-of-service time and !
to reduce outage worker dose. In addition, the lack of preparations placed a higher than l necessary burden on the control room operations crew to ensure the outage progressed i safely and in compliance with T/Ss. However, the inspectors did note a significant ;
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improvement by the licensee in terms of the quality and timeliness of the preparations !
for U2R23 compared to previous refueling outages planned by the license j Conclusions Overall, although the planning for the Unit 2 cycle 23 refueling outage improved from that of previous outages, the licensee did not meet its own pre-outage planning milestones, resulting in the potential for poor quality outage work documents and unnecessary worker radiation exposure. In addition, this pre-outage plan implementation problem reduced the time available to the licensee to perform risk and safety assessments of the scheduled outage work and to identify potential T/S conflicts, instead placing those burdens on control room operator .3 Unit 2 Shutdown for U2R23 Inspection Scope (IP 71707)
The inspectors observed the shutdown of Unit 2 in preparation for U2R2 Observations and Findinas On December 4,1998, the licensee commenced the shutdown of Unit 2 using Operating Procedure (OP) 3A, " Normal Power Operation to Low Power Operation," Revision 43 and OP 3B, " Reactor Shutdown," Revision 27. The inspectors observed the shutdown from the control room and had the following observations:
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The licensee dedicated the operating supervisor (OS), a senior reactor operator (SRO), to provide direction and close supervision for the Unit 2 shutdown. The inspectors found that this practice aided in minimizing the distractions to Unit 1 l and also provided a clear focal point for command and control of Unit .
The appropriate procedures were present and in use by the control room operators. The inspectors noted an instance where the OS intended to proceed beyond Step 4.13.8 of OP 3A. When the inspectors questioned the OS, he explained he believed his implementation of the procedure was consistent with the guidance contained in Operations Manual (OM) 1.4, "Use of Operations Group Procedures and Work Plans," Revision 1. The OS checked OM 1.4 and found that it did require the procedure step in question to be completed prior to
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proceeding to subsequent steps, contrary to his belief. The OS waited for OP 3A, Step 4.13.8 to be completed and then continued with the remainder of OP 3 .
Communications among the operating crew generally conformed with station procedures, in terms of the use of two- and three-way communication However, the messages communicated frequently were informal and imprecise, I especially when providing equipment manipulation direction or relaying plant information. The OS briefed the crew prior to commencing different portions of the shutdown procedure. The inspectors concluded that this practice enhanced l
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crew awareness and allowed the crew to review their expected actions and obtain clarification for any uncertaintie . The OS attempted to minimize the distractions to the crew and limit control room access during the Unit 2 shutdown. The reactor (control) operators (COs) did limit the number of people allowed inside of the "at the controls" area. However, during various periods of the shutdown, there were up to six operator license trainees, an outage manager, two assistant operations managers, and a quality verification (QV) department inspector, in addition to the normal operations crew of six, all simultaneously within the controlled area of the control room. The inspectors asked the OS about the number of nonessential personnel and he responded that he would limit the number of people in the control room to something reasonable, but that number had not yet been reached. The inspectors did not observe any direct impact on the operating crew from having a large contingent of licensee personnel in the control room, but it did create the potential for distractions during a entical evolutio .
The licensee maintained good control over reactivity manipulations. The OS dedicated a CO to monitor and control reactor parameters while another CO attended to the secondary plant. The two COs exhibited good teamwork and coordination when making equipment status changes that might impact reactivity. The inspectors noted that the COs used peer checks, self-checking, and multiple independent parameter indications when making reactivity change .
Operator control board awareness varied during the Unit 2 shutdown. In one instance, the COs did not notice the change in state of a reactor trip block status light until the duty operating supervisor (DOS), supervising Unit 1, pointed it out to the Unit 2 COs and O Demonstrating good control board awareness, a CO identified one of the two pens on the nuclear instrument output recorder (2NR-45) sticking, and had to repeatedly unstick it during the shutdown. However, both the CO and OS did not follow through by initiating an equipment work request or identifying the pen as having the potential to stick. The problem was not appropriately addressed until several days later when a CO noticed the same recorder pen sticking and unstuck it. The inspectors asked the DOS if an equipment work request should be initiated to correct the problem. The DOS had the CO generate an equipment work request as well as a deficiency tag identifying the pen as sticking. In this instance, several operators and their supervisors did not pursue appropriate correction of a faulty control room indicator until prompted by the inspector At approximately 18 percent power, the indication for the controlling steam flow channel of the Unit 2 "A" steam generator water level control system failed downscale. The CO took manual control of the "A" steam generator water level control system and restored level within the desired band. The CO then selected the other available steam flow channel as an input signal and placed the control system back into automatic. The CO displayed good control board awareness by detecting the failed steam flow channel indication and taking appropriate action. However, the failed channel had been previously identified by the
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l l licensee as failing downscale during low power operations. The licensee had placed it on the operator workaround list. The inspectors questioned the OS as to why a known " bad" channel had been used as an input into the automatic steam generator water level control system during a low power evolution instead of the channel with no known problems. The OS stated that it probably happened to be the channel maintenance personnel had left selected following the last time the surveillance had been done on the steam flow signal. The inspectors concluded that an unnecessary challenge to the plant and the operators occurred because of poor configuration control of a known operator workaround, especially for a planned evolution leading to circumstances where the equipment was known to fai During the shutdown, the control room received numerous high level alarms for the number 2 and 3 low pressure feedwater heater strings. The COs responded in accordance with station procedures for unexpected alarms and ultimately dispatched auxiliary operators (AOs) to locally investigate the high levels. The AOs reported that the feedwater heater dump valves were closed even though the associated level controllers were demanding them to open since the feedwater heater levels were above the setpoints. The COs directed the AOs to l adjust the controllers'setpoints to open the dump valves to clear the high level conditions. The AOs experienced difficulty in clearing the high level alarms i because of their unfamiliarity with the task of adjusting the controllers'setpoint j After several minutes of continued distraction to the COs from attempting to help ;
the AOs, the duty shift superintendent (DSS), the senior licensed individual in the control room, left the control room and went to assist the AOs in clearing the feedwater heater high levels. Approximately 30 minutes after receipt of the first high level alarm, the DSS and AOs successfully opened the dump valves and ;
lowered the feedwater heater levels, clearing the alarm ;
The inspectors learned that it had been a common station practice to have to i manually exercise the dump valves prior to their automatic operation. This practice was the result of the dump valves sticking in the closed position because they were not normally operated during power operation. Additionally, the high levels in the low pressure feedwater heaters were not unexpected for operation of the unit at lower reactor power levels since the feedwater heater level controls had been optimized for 100 percent power conditions. The inspectors also determined that no procedural guidance existed for adjusting the dump valve controllers'setpoints. These observations led the inspectors to conclude the following: The fact that historically the dump valves would not open when required and needed operator intervention was an unidentified operator workaround and a material condition issu . The licensee considered the adjustment of a valve controller setpoint to be within the skill-of-the-craft of an AO and concluded no procedure was required. Based on the fact that operators in the control room (including the DSS) had to help the AOs to adjust and regain feedwater heater level control, the inspectors questioned whether AO training was adequate or if
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procedures were needed for these manipulations. This situation was similar to recent inspector findings regarding the difficulty that the licensee was having in determining which tasks should be considered within the skill-of-the-craft or required procedure The inspectors discussed these observations with plant management on December 18, 1998. Plant management stated that the issues would be reviewed and appropriate
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, Conclusions Operators safely shut down Unit 2 for the refueling outage. However, poor material condition, unresolved operator workarounds, and a lack of procedures resulted in a distraction to operators and required operator intervention during a critical and complex evolutio O2 Operational Status of Facilities and Equipment i
O2.1 Cold Weather Preoarations
! Inspection Scope (IP 71714)
The inspectors reviewed the licensee's cold weather preparations and walked down portions of the plant subject to severe cold weather conditions. Particular attention was focused on arecs identified as being subject to reoccurring problems in IP 71714 and in a previous inspection (Inspection Report (IR) 50-266/97003(DRP); 50-301/97003(DRP)). Observations and Findinas The inspectors concluded that the licensee had implemented their cold weather preparation checks in accordance with operations department Periodic Check (PC) 49, l " Cold Weather," Parts 1 through 5.- Adequate insulation and heat tracing or room L heating was observed in all areas inspected. Several minor discrepancies were
- observed, and reported to the licensee for correctio While no immediate safety concems were identified, the inspectors did have several questions about the plant's cold weather preparation program. These questions were discussed with the licensee, who indicated that each question would be evaluated. The specific questions were
l . It was not clear to the inspectors how the licensee ensured that systems or
! equipment removed from service, such as for U2R23, were evaluated for the adequacy of cold weather protection (if needed) in their out-of-service configuratio * The ventilation systems in the circulating water pump house (containing the safety-related service water (SW) system pumps and piping), the safety-related
! diesel generator building, and the station blackout gas turbine building were not i
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covered by operating procedures. While checklist PC 49 required a one-time check to ensure that ventilation system heaters for these areas were operating, it was not clear what, if any, controls existed to ensure that these heaters were maintained operable and in their intended configuration. As an example, the inspectors identified that one heater (HX-2718) in the diesel generator fuel oil transfer pump room had been turned off. This heater had been verified to be on during the earlier performance of PC 4 Near the end of this inspection period, as a result of equipment problems because of recent severe cold weather, the licensee identified deficiencies with the operation of the facade freeze protection system. Some were repetitive from previous years. In response, the licensee entered the deficiencies into the corrective action system and '
plant management directed a root cause evaluation be conducted to address the issu The inspectors will track the licensee's evaluation of the above inspector-identified issues and the corrective actions for the licensee-identified facade freeze protection system deficiencies as an Inspection Followup item ((IFI) 50-266/98021-01(DRP);
50-301/98021-01(DRP)). j On January 5,1999, one day after the end of the inspection period, the inspectors questioned the licensee about a work request dated December 22,1998, for the heat tracing associated with the "fillline" for the Unit i refueling water storage tank. In I addressing the question, the licensee identified that the fill line also functioned as '
minimum flow line for the safety injection pumps. A subsequent test determined that the line was frozen, rendering both trains of the Unit 1 safety injection system inoperabl l This issue will be reviewed further by the inspectors as part of a specialinspection and l documented in IR 50-266/99004(DRP); 50-301/99004(DRP).
I l Conclusions l The inspectors verified that the licensee had completed the cold weather preparation checklist; however, there was no checklist item or procedure for ensuring that ventilation ;
systems used to protect safety-related equipment from cold weather were maintained in the proper configuration after performance of the checklist. Additionally, at the end of the inspection period, the licensee identified problems with maintaining the containment facade freeze protection equipment operational after the checklist was complete Operations Procodures and Documentation l 03.1 Operations Department Procedure Adherence Inspection Scoce (IP 71707)
The inspectors continued their ongoing review of the licensee's standards and guidelines on procedure use and adherenc .. . .. --. _ _ . - _ . _- - _ _ _ _ . _ . - .
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l Observations and Findinas While monitoring the removal of the Unit 2 RV head, the inspectors identified two issues conceming licensee procedure adherence standards. The inspectors observed four SROs, one of whom was the DSS, address an apparent problem with the step sequence in the operations department procedure for RV head removal. During their conversation, the four SROs agreed that the steps in this procedure did not have to be j performed in the sequence v/ritten because the procedure was a " Reference Use" l procedure, not a " Continuous Use" procedure. The inspectors asked the DSS what document authorized performing procedure steps out of sequence. The DSS indicated l that OM 1.4 authorized SROs to approve the modification of step sequences in
, " Reference Use" procedures. However, after a review of OM 1.4, the DSS concluded i that procedure steps did have to be performed in the sequence specified (unless the I approved procedure allowed deviation from the sequence). The inspectors were concerned that an entire on-shift crew of SROs misunderstood the licensee's procedure adherence requirements in this instance. This concem was further increased by the fact that the performance of procedure steps in the sequence specified is a fundamental aspect of performing procedures as written, a regulatory and licensing requirement (10 CFR 50, Appendix B, Criterion V, and T/S 15.6.8.1). Based upon these observations and those documented in previous irs, the inspectors concluded that I some of the procedure adherence requirements of OM 1.4 were not clear or well i understood by licensee staf l l l The second procedure adherence issue involved the coordination of multiple procedures being performed in parallel. The RV head had been lifted approximately four feet off of the RV flange and operators had flooded the refueling cavity to approximately one foot f above the flange. The licensee performed an inspection of the RV keyway to determine whether the cavity-to-vessel seal ring was leaking. Neither the operations department procedure nor the maintenance department procedure in use specified acceptance l criteria for allowed leakage. The person who entered the keyway noted leakage from the seal ring, but did not feel qualified to determine whether the observed leakage was acceptable. The operations department procedure allowed proceeding through several ,
additional steps Deiween the performance of the inspection before a determination of '
leakage acceptance was required. The maintenance department procedure required l
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successful completion of the test before proceeding. Work was continued in both .
procedures prior to a formal resolution of the acceptability of the inspection because of poor communications between the DSS, the maintenance department lead supervisor, and the support staff involved with the inspection and its evaluation. The observed leakage was minor, and was subsequently determined to be acceptable by qualified staff. Proceeding in the maintenance department procedure prior to the resolution of the leakage test acceptability constitutes a violation of minor safety significance and is not subject to formal enforcement actio The inspectors were concerned however that plant staff had not ensured the following:
i a the inspection was performed by someone qualified to assess the acceptability of l the inspection results, i
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a step requiring successful completion of the inspection was signed-off as complete prior to a determination that the inspection results were acceptable because of poor communications between the control room and the staff inside containment, and
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the senior outage manager present in the containment, who was aware of the confusion over the inspection results, did not ensure that plant staff paused in the performance of the activities long enough to ensure that they understood the issues at hand and were in conformance with the procedure These observations were discussed with the involved plant staf Conclusions The inspectors' observations of the Unit 2 reactor vessel head lift indicated the continued need for licensee focus on conservative plant operation and proper procedure usage during major refueling activities. These observations and those documented in previous inspection reports reinforce the inspectors' concerns with some operators'
understanding of procedure adherence requirements and with the unclear guidance contained in OM 1.4 regarding these requirements. Also, p! ant staff did not ensure adequate coordination of two procedures being used in parallel during the leak check inspection of the cavity-to-vessel seal ring during cavity flood-u Operator Knowledge and Performance 04.1 . Operator Response Durina The Unit 1 "A" Steam Generator Feedwater Pumo Event Inspection Scope (IP 71707)
The inspectors reviewed operator performance during the November 14,1998, rapid reactor down power and removal from service of the Unit 1 "A" steam generator feedwater pump because of an outboard pump bearing failure. The inspectors' initial review of the event is discussed in IR 50-266/98019(DRP); 50-301/98019(DRP)
Section 0 Observations and Findinos in response to the control room indications and field reports, the control roem crew implemented Abnormal Operating Procedure (AOP) 2B, "Feedwater System Malfunction," Revision 5 and AOP 17A, " Rapid Power Reduction," Revision 4. The j inspectors interviewed the control room personnel involved in the event and reviewed l the response of plant safety systems. The control room crew during the event l
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considered whether to trip the reactor or attempt to reduce power and keep Unit 1 online, choosing the latter, The OS established criteria and informed the COs under I which conditions to trip the reactor. The inspectors determined that the operators i exercised conservative decision-making and properly balanced reactor safety with l operating the plant in a deliberate and controlled manner. The inspectors concluded
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l i that the AOPs were properly implemented given the event circumstances and that plant i safety systems responded appropriately.
1 However, the inspectors learned through the interviews that operators are expected by l plant management to take certain "immediate" actions of the AOPs from memory. The
expectation was promulgated via a memo from the operations manager to the
, operations personnel. The extent and type of actions to take prior to implementing the L AOPs are not defined or identified in the AOPs in terms of which steps should or could l
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be accomplished without the procedure in hand and from memory. The AOPs were classified by the licensee as " Continuous Use" procedures, meaning that the procedures
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response during plant transients and the improper implementation of the AOPs. In addition, the licensee's practice of using a memo to exempt certain proceduralized
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operator actions from " Continuous Use" status appeared inconsistent with the procedure use requirements of OM 1.4. The inspectors discussed these concerns with plant management who acknowledged the concerns. However, the licensee decided further l study of the concerns was required prior to making any changes to the expectations for AOP use. The inspectors will track the licensee's response as an Unresolved Item ((URI) S0-266/98021-02(DRP); 50-301/98021-02(DRP)).
- Conclusions I
l Operators responded appropriately during the November 14,1998, rapid reactor down l power and removal from service of the Unit 1 "A" steam generator feedwater pump
[ because of an outboard pump bearing failure. The inspectors identified concerns regarding the potential for inconsistent operator transient response and abnormal operating procedure usage and implementation.
l 07 Quality Assurance in Operations 07.1 QV Department Observation of Unit 2 Shutdown (IP 71707)
The QV department observed the U2R23 shutdown (Section O1.3). The inspectors l reviewed Work Monitoring Report (WMR) 98-0402, which documented the QV
- department's findings from these observations. The WMR cited no deficiencies, did not l
document any potential areas for improvement, and described the entire shutdown in positive terms. The WMR-documented observations contrasted sharply with the inspectors' observations (Section 01.3) of the same evolution. The lack of self-critical observations called into question the depth and quality of the QV department's operations monitoring capability. The inspectors discussed this issue with QV department supervision who acknowledged the concern. They expected improvement l in their operations-related monitoring capability in the near future because of the recent l hiring of personnel with operations experience.
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Conclusions The quality verification department did not identify any issues during Unit 2 shutdown observations, including those issues identified by the inspectors. This lack of issues called into question the effectiveness of the quality verification department's operations-related effort .2 Manaoement of Reoulatory Commitments Inspection Scope UP 4050Q)
The inspectors reviewed CRs 98-3394,98-4087 and 98-416 Observations and Findingg On September 14,1998, CR 98-3394 documented a failure to implement a 1981 written licensee commitment to the NRC allowing only one charging pump to be in service during cold shutdown with the other two charging pumps (danger) tagged out-of-servic . The commitment's purpose had been to ensure that control room operators had at least 15 minutes to mitigate a cold shutdown boron dilution event. The corrective action planned for CR 98-3394 included the preparation of a commitment change form and a 10 CFR 50.59 evaluation to eliminate the commitmen On December 15, CR 98-4087 documented that Unit 2 entered cold shutdown for U2R23 without complying with the 1981 commitment on charging pumps. The licensee had not completed the corrective action for CR 98-3394 and failed to identified it as needing to be done prior to U2R23. In addition, the licensee failed to identify and l implement any interim measures to ensure compliance until the commitment was !
changed. In response to CR 98-4087, plant management initiated a root cause evaluation to determine why corrective actions for the September 1998 problem were not timel On December 21, CR 98-4162 documented the failure to implement a written commitment made to the NRC in 1990 concerning implementing an emergency diesel generator reliability program that conbrmed to Regulatory Guide 1.155, " Station Blackout." No licensee corrective actions for CR 98-4162 were developed by th end of this inspection perio i Section 08.1 of IR BO-266/9701?(DRP); 50-301/97016(DRP) documented several significant defit,iencies in the licensee's management of NRC commitments. The inspectors were concerned that deficiencies still existed in the licensee's NRC commitment tranagement program. The inspectors shared the concern with the licensing manager. Tht< licensing manager described existing plans for a program for improving NRC commitment management but stated that the program would not be fully implemented for several year !
. . Conclusions Deficiencies existed in the licensee's Nuclear Regulatory Commission commitment management program similar to problems identified by the inspectors in 199 Miscellaneous Operations issues 08.1 LQtosed) Inspection Followuo item (IFI) 50-266/98009-07(DRP):
50-301/98009-07(DRP): * Evaluation of load to main steam piping from inadequate drains." The main steam system engineer informed the inspectors that drain lines would be added to the system piping so that all major pipe sections had adequate drain paths during pipeline heat-up. This addressed the inspectors' concem .2 (Closed)IFl 50-266/97020-02(DRP): 50-301/97020-02 (DRP): " Assess procedural controls." This issue has been superseded by an Unresolved item ((URI) 50-266/98019-01(DRP); 50-301/98019-01(DRP)).
08.3 (Closed) Violation (VIO) 50-301/97006-01a(DRP): " Corrective actions for blocking device removal." The inspectors verified the corrective actions described in the licensee's response letter, dated June 23,1997, to be reasonable and complete. No similar problems were identifie .4 (Closed) VIO 50-266/97013-01(DRP): 50-301/97013-01(DRP): " Failure to follow procedure for alarm response." The licensee had taken corrective action for this item prior to issuance of the IR in which it was cited; therefore, no additional corrective actions were required. The inspectors verified that operators routinely consulted alarm response books when alarms were receive .5 fClosed) VIO 50-266/97013-03(DRP): 50-301/97013-03(DRP): " Procedural deficiencies cause valve mispositioning events." The inspectors verified that the licensee had documented all corrective actions as being complete. The inspectors also discussed with the operations ' manager the licensee's broader initiatives to ensure better coordination of procedures. These initiatives appeared reasonable to preclude similar future problem .6 (Closed) Escalated Enforcement item (EEI) 50-266/97005-01(DRP):
50-301/97005-01(DRP): " Change to operation of motor-driven auxiliary feedwater (AFW) pump was an unreviewed safety question." This issue was cited as example 2 of violation B in Enforcement Action 97-075. The inspectors verified that the corrective actions specified by the licensee were appropriate. Significant improvements in the performance of safety evaluations have been observed since the time in which this violation occurre .7 (Closed) VIO 50-266/96015-02(DRP): "T/S full pressure test not done." This violation involved the licensee's failure to perform a required full pressure test of the Unit 1
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personnel containment hatch when leak rate test results for the hatch exceeded the limits of T/S 15.4.4.ll.B.2.a. The licensee subsequently modified the leak rate test procedure to specify the full pressure test when leak rates exceeded T/S limit l
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08.8 (Closed) VIO 50-266/97006-01c(DRP): " Corrective actions for reactor coolant system draindown events." The inspectors verified that the corrective actions described in the licensee's response letter, dated June 23,1997, were reasonable and appropriat .9 (Closed) VIO 50-266/96015-03a(DRP): 50-301/96015-03a(DRP): " Appendix B, Criterion XVI, corrective actions problem." This example of a 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Actions," violation involved the licensee's failure to adequately address previously identified weaknesses with the containment hatch leak testing program. The corrective actions taken to address this violation have been implemented and are considered reasonable to prevent recurrenc .10 (Closed) VIO 50-266/97003-02a.b.c(DRP): " Crossover and condenser steam dump valves and component cooling water (CCW) pump impeller cracks." The inspectors verified the corrective actions described in the licensee's response letter, dated July 7, 1997, to be reasonable and complete. No similar problems were identifie II. Maintenance ;
M1 Conduct of Maintenance l
M1.1 AFW Pumo (P-388) Outaoe Inspection Scope (IPs 62707 & 71707)
The inspectors reviewed selected activities associated with a planned maintenance outage for the "B" motor-driven AFW pump (P-388). Observations and Findinos
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As part of the licensee's work control process, a work-week coordinator was assigned responsibility for planning and coordinating the activities associated with the maintenance outage for P-38B. The inspectors reviewed the P-388 outage preparations and monitored the outage execution. The inspectors determined that the work-week coordinator sufficiently planned the outage and coordinated the numerous associated work activities, such that P-38B was returned to service as scheduled, thus avoiding any unnecessary out-of-service tim The inspectors reviewed the danger (equipment isolation) tag clearance developed for the P-38B outage, Clearance No. 0-DT-98-1004, Revision 2, against plant drawing The inspectors concluded that the protective boundary established by the clearance provided adequate protection for plant equipment and personnel given the scope of planned maintenance activities. During a walkdown of the tagging boundary, the inspectors identified no discrepancies between the danger tag paperwork and the equipment that was tagged. The inspectors noted that workers properly signed onto and off of the clearance in accordance with station procedures. Following completion of the P-38B outage, the inspectors verified the proper removal of the danger tag clearance for P-38B and the proper realignment of P-388 into an operable configuratio . . _ . . . _ _ _ _ .- _ _ _ _ . . ._.
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The inspectors observed portions of the following maintenance work activities: ,
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Work Order (WO) 9711349, "AF-4019 Valve Oscillates," I
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WO 9715666, "AF-4019 Limit Switch Repair," l
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WO 9803397," Replace Agastat Relay 62/P-038B," l
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WO 9710104, "AF-4020 Packing Leak,"
WO 9809083, "AF-4020 Motor Operated Valve Preventative Maintenance," and a WO 9708239, " Repair P-38B Control Switch."
Maintenance personnel properly utilized the WO paperwork to accomplish the planned ,
work activities. Proper foreign material control and housekeeping practices existed l during the maintenance work. The inspectors determined that, in general, the work l associated with these activities was conducted in a professional and thorough manne The maintenance personnel were knowledgeable of their assigned tasks and work document requirement Conclusions The licensee's use of a work-week coordinator facilitated the completion of the *B" motor-driven auxiliary feedwater pump outage, thereby, minimizing equipment out-of-service time. The maintenance activities were conducted in an acceptable manner, using the appropriate paperwor l l
M1.2 Unit 1 CCW Pumo "A" Seal Failure i Inspection Scope (IP 62707) !
The inspectors observed portions of the work activities associated with the repair of the '
Unit 1 "A" CCW pump (1P-11 A) inboard sea Observations and Findinas On December 23,1998, the inboard pump seal of 1P-11 A failed while in service which required operators to place 1P-11B into service and declare 1P-11A inoperable. The control room crew appropriately recognized the applicability of T/S 15.3.3.C.2.a,
" Component Cooling Water," and applied the 72-hour restriction on the continued operation of Unit 1. Because of the short T/S-allowed outage time, the control room crew immediately mobilized the required personnel to promptly repair the pum Operators hung Clearance No.1-DT-98-2494, Revision 0, to provide a boundary for 1P-11 A seal repair work. The inspectors determined that the clearance had been properly authorized, and using controlled drawir.gs, verified that the clearance boundary
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provided adequate equipment isolation and personnel protection. The inspectors walked down the clearance and concluded the correct components were removed from
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servic The inspectors observed the maintenance crew repair 1P-11 A. The workers used the cor.ect personnel protective equipment to minimize exposure to the potassium chromate-treated CCW water during pump disassembly and exercised adequate foreign material exclusion and housekeeping controls. The inspectors reviewed Work Plan 9819905, " Replace leaking 1P-1 in inocard pump seal," and Routine Maintenance Procedure 9006-5, " Component Cooling Water Pump Overhaul," Revision 5. Both documents appeared sufficiently detailed for the scope of the planned repair. The inspectors observed that the maintenance crew followed the sequence of steps in the work documents. The remaining operable Unit 1 "B" CCW pump was in close proximity to 1P-11 A and the maintenance crew demonstrated the proper sensitivity to the work environmen Pump seal leakage for both the Units 1 and 2 CCW pumps had been previously identified as a problem by the licensee prior to the December 23,1998,1P-11 A seal failure. In fact, during the iP-11 A return-to-service testing, the outboard pump seat leakage rate exceeded acceptance limits and was also replaced. The licensee had determined that the excessive leakage resulted from a combination of operating the pumps, which were sized to mitigate accidents, at the lower flow rates of normal plant operation and the pumps' suction and discharge piping layout. Also, after a CCW pump seal leak developed, potassium chromate crystals likely formed in the pump seal areas, accelerating seal degradatio Pump seal leakage was collected in temporary plastic containers instead of being l allowed to drain into and contaminate the normal plant waste water system. The AOs were required to periodically monitor the volume and change out the plastic container l
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The licensee had identified this as an operator workaroun Prior to 1997, the licensee attempted to correct the seal leakage problem by installation of a seal of a different design. That design was not fully successful at preventing excessive leakage either, although it was easier for maintenance personnel to change out. Since 1997, the engineering department had been working with the pump manufacturer and developed a new seal package design as a long-term solution, but was not planning to install it until late in 199 c. Conclusions The repairs of the Unit 1 "A" component coo!ing water pump were conducted in a manner commensurate with the safety significance of the job. Proper controls were used to minimize potentialimpact on the remaining operable Unit 1 *B" component cooling water pump. The inspectors concluded that the long-standing component cooling water pump seal material condition / design issue had not yet been resolved, which had resulted in a failure of safety-related equipment and the continued existence of an operator workaroun . . _ - - -. . - - - -_ - - - - -
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M8 Miscellaneous Maintenance issues M8.1 (Closed) IFl 50-266/97003-03(DRP): 50-301/97003-03(DRP): "AFW assumption validity in SW system calculation." The inspectors verified that the Point Beach licensing basis did not require the plant to be capable of sustaining a design basis earthquake and loss of coolant accident concurrently. Based on this information, the inspectors considered the assumptions used in the licensee's SW system calculation to be vali M8.2 (Closed) VIO 50-266/97013-05(DRP): 50-301/97013-05(DRP): " Failure to calibrate maintenance and test equipment." The inspectors verified that the licensee had included the subject equipment in the calibration program.
l M8.3 (Closed) IFl 50-266/97006-02(DRP): 50-301/97006-02(DRP): * Maintenance program improvement initiatives." The inspectors opened this item to monitor the licensee's progress in addressing several QV department and inspector-identified deficiencies in the maintenance program. The plant has taken steps to address the original concerns, including the hiring of a new maintenance manager. The new manager has refocused the maintenance organization on improvement items and has supplemented his staff j with industry-experienced personnel to assist in implementing these changes.
l l M8.4 (Closed) VIO 50-266/96015-03b(DRP): 50-301/96015-03b(DRP): " Appendix B, l Criterion XVI, corrective actions problem." This example of a 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Actions," violation involved the licensee's failure to promptly resolve questionable surveillance test data following a test of the "A" motor-driven AFW pump. Actions taken to address this violation included stipulations in test procedures that required the resolution of any questionable or unexpected data prior to
! the component being declared back in service.
l lil. Enaineerina E2 Engineering Support of Facilities and Equipment E Modification to Safety Iniection (SI) System Inspection Scope (IP 37551)
The inspectors reviewed the licensee's engineering evaluations, installation procedures, and actual performance of work involving a modification to the SI system. The major l purpose of the modification was to convert the manual residual heat removal (RHR)
heat exchanger to SI pump suction isolation valves into motor-operated valves (MOVs).
l Documents reviewed during this inspection activity included the following:
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Safety Evaluation 98-171, " Convert 2SI-857A(B) to MOVs and 2SI-897A(B) to Fail Open," dated November 30,1998, e installation Work Plan (IWP)-97-085*A-01, *New Terminal Box, Conduit, and Cable installation For 2SI-857A and 2SI-857B," approved on December 1,1998,
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lWP-97085*A-02, "RHR Heat Exchanger Outlet to St Pump Suction isolation Valves 2SI-857A and 2SI-8578," approved on December 1,1998, and
IWP-97-085*B-01, " Conversion of 2SI-857A and 2SI-857B Valves - Mechanical and Civil," approved on December 1,199 Observations and Findinos Backoround
, The required operator actions to place the plant into the post-accident recirculation l phase configuration included the local manual opening of the SI pump suction isolation valves from the RHR heat exchangers and the local manual manipulation of the Si test retum line isolation valves. To perform these local actions required operators to enter a post accident, and potentially radiologically harsh, environment. These operator work workarounds were significant contributors to the loss of coolant accident core damage frequencie Modification Scope A modification was developed to convert the Si pump suction isolation valves from the l RHR heat exchangers (2SI-857A & B) from manual valve operators to motor-operated valves. The handswitches for the motor operators would be located in the control roo In addition, a modification was developed to eliminate the manual action necessary to remove the " gags" on the Si pump test return line isolation valves which were in place to maintain the valves open in the event of a loss of instrument air. The valves would be
converted from fail-close to fail-open valves, thus eliminating the need for operators to remove the gags when the Si system was placed on containment sump recirculatio j Effects on Core Damaoe Frecuency I The most recent probabilistic safety analysis indicated that the single most significant action contributing to the overall plant core damage frequency was the dependency on manual alignment of the Si system for the recirculation phase. In particular, this action was very significantly weighted for loss of coolant accident scenarios.
l i The installation of this modification would provide an approximate 10 percent reduction l in the overall plant core damage frequency and a greater than 60 percent reduction in the core damage frequencies for loss of coolant accidents.
l The current probabilistic safety analysis established a core damage frequency of 8.3 X 10-5 events / year. Loss of coolant accidents accounted for about 28 percent of the initiating event scenario Assessment of Work Activities
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The inspectors observed modification planning meetings prior to the start of U2R23 and noted a clear commitment from plant management to perform the modification. The
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l modification had been proposed in the past, but had not been implemented. The decision to follow through on the installation of this modification illustrated the current plant management's sensitivity to risk-significant activities from a core damage ;
frequency perspectiv I The inspectors reviewed the safety evaluation and installation work procedures for the modification. The safety evaluation thoroughly addressed the design change and the installation work plans contained step-by-step instructions, quality control hold points at appropriate steps, and foreign material exclusion notes and precautions. The inspectors identified no concems with the safety evaluation and installation work procedures reviewe Conclusions Station management displayed conservative, risk-based decision-making regarding the approval and installation of a Unit 2 safety injection system modification. The modification was intended to address the long-standing need to use manual actions after an accident to align the safety injection system for the recirculation phase. The inspectors identified no concerns with the safety evaluation and installation work plans for the modificatio E4 Engineering Staff Knowledge and Performance E4.1 CCW Minimum Temoerature (IP 37551 During a walkdown of the operating Unit 2 RHR pump, the inspectors noticed the CCW supply line to the oil cooler felt very cold. The inspectors, concerned about the impact the low temperature may have on the RHR pump oil properties, consulted the CCW system engineer. The recently assigned CCW system engineer did not immediately know of any minimum CCW temperature operating restrictions. The engineer pursued the issue further and determined the minimum design CCW temperature was 40 degrees Fahrenheit (*F). The engineer additionally confirmed that the RHR pumps had been specifically evaluated for the 40 *F temperatur The inspectors questioned what controls were in place to prevent operation below the CCW minimum design temperature. The system engineer determined that no controls were specifically in place to limit a low CCW temperature other than the controls placed upon the SW minimum temperature (also 40 *F) which cooled CCW; thereby, indirectly limiting the minimum CCW temperature. The inspectors concluded that the potential for actually operating CCW below the minimum design temperature was minimal, but the licensee failed to have any mechanism in place that specifically identified the minimum acceptable CCW operating temperature and prevent going below the minimum CCW design temperature. This failure to comply with 10 CFR Part 50, Appendix B, Criterion lil, * Design Control," constitutes a violation of minor significance and is not subject to formal enforcement action.
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. Conclusions The component cooling water system engineer's knowledge of assigned system fundamental characteristics was adequate, even though he was only recently given responsibility for the system. The inspectors identified the lack of controls to specifically limit the minimum component cooling water system operating temperature to within its i design valu l E7 Quality Assurance in Engineering Activities l E QV Deoartment Surveillance of Soecial Nuclear Material Control and Nuclear Fuel
, Inspection Scope (IP 40500)
The inspectors reviewed QV department report number S-P-98-11 for the surveillance conducted on November 9 through 18,199 Observations and Findinas The surveillance assessed the nuclear fuel functional area, including special nuclear material control and accounting, nuclear fuel reliability, and how well past issues had been resolved. In addition, the QV department reviewed the status and effectiveness of
the recent self-assessment by the reactor engineering group.
The surveillance concluded that the nuclear fuel functional area was effective and did not identify any concerns in the design controls for reload cores. Also, actions taken by the reactor engineering group had been successful in identifying problem areas and addressing them. One Quality CR 98-0356 was generated during the QV department assessment and pertained to eye examination requirements for personnel performing i
visual fuel receipt inspections.
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The inspectors determined that the surveillance plan and checklist used by the QV department was broad and relied on source documents for assessment. The use of a technical specialist from another nuclear plant provided an independent perspective to the licensee's assessment. The surveillance of the reactor engineering area characterized the actions taken in response to the self-assessment as adequate. The inspectors also concluded that the reactor engineering actions appeared adequate. But, the QV department failed to emphasize that the actions had been delayed several times
, and were still incomplete even though they had been identified as highest priority item Conclusions
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The licensee performed an assessment of the nuclear fuel function area relying on -l
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source documents and using offsite technical expertise. The inspectors concluded that the assessment of corrective action content appeared adequate but that the licensee failed to recognize that completing those actions in a timely manner was also important.
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E8 Miscellaneous Engineering issues E (Closed) IFl 50-266/97021-03(DRP): 50-301/97021-03(DRP): "CCW treated as closed system without boundary checks." The inspectors could not identify any requirement to perform boundary leak checks for systems classified as " closed outside containment."
Additionally, the licensee was pursuing a change to their licensing basis to treat CCW as a " closed system inside containment." This change will address the inspectors'
concern E8.2 (Closed) Licensee Event Report (LER) 50-301/97001: " Containment liner clearance not in accordance with plant design basis." This LER documented a condition which had existed since plant construction. The licensee took appropriate action to bring the plant into conformance with its design basi E8.3 (Closed) LER 50-266/96013: 50-301/96013: " Potential common mode failure in 120-volt alternating current instrument power supplies." This LER documented a condition under which design basis safety functions would not have been operable because of a common mode failure mechanism. This mechanism (a design flaw) involved the current limiting characteristics of the 120-volt alternating current static inverters in combination with the lack of physical separation of the nonsafety-related circuits that were powered from each inverter. The inspectors verified that corrective actions were appropriat These actions included the permanent powering of the circuits from different power supplies. The common mode failure mechanism had been introduced by a modification performed in 1982. This non-repetitive, licensee-identified and corrected inadequate modification is being treated as a Non-Cited Violation ((NCV) 50-266/98021-03(DRP);
50-301/98021-03(DRP)) of 10 CFR Part 50, Appendix B, Criterion lil, " Design Control,"
consistent with Section Vll.B.1 of the NRC Enforcement Polic E8.4 (Closed) VIO 50-266/96019-05(DRP): 50-301/96019-05(DRP): * inadequate corrective actions / main steam safety valve setpoint drift." The inspectors verified that corrective actions had been documented as complete. Improvements in the licensee's operating experience and corrective action programs have been noted since this violation was cite E8.5 (Closed) VIO 50-266/96015-03c(DRP): 50-301/96015-03c(DRP): " Appendix B, Criterion XVI, corrective action problem." This example of a 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Actions," violation involved the licensee's failure to properly test air start motor sequences for the Unit 1 and Unit 2 Train A emergency diesel generators. The air start motor sequence testing procedures have been revised to ensure that the equipment is tested consistent with Section 8.2.3 of the Final Safety Analysis Repor E8.6 (Closed) eel 50-266/98019-02b(DRP): " Failure to complete system pressure tests."
Section E1.2 of IR 50-266/98019(DRP); 50-301/98019(DRP) documented an example of an apparent violation of T/S 15.4.2.B.1. The licensee subsequently submitted LER 50-266/98028 which contained information regarding the reason for the apparent violation, and the corrective actions taken and planned to correct the apparent violation and prevent recurrence. The inspectors reviewed the information and found the cause
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l and corrective actions appropriate. Failure to perform the required tests is a violation of T/S 15.4.2.B.1 which requires the systems to be inspected as specified by Section XI of the American Society of Mechanical Engineers (ASME) Code. Even though this failure was licensee-identified, because of its repetitive nature, it is being treated as an example of a cited violation (VIO 50-266/98021-04a(DRP)) with no licensee response require E8.7 (Closed) eel 50-266/98019-02a(DRP): 50-301/98019-02a(DRP): * Failure to adequately complete the Code VT-2 visual examination of the Units 1 and 2 spent fuel storage pool." Section E1.2 of IR 50-266/98019(DRP); 50-301/98019(DRP) documented an example of an apparent violation of T/S 15.4.2.B.1. Subsequently, the licensee developed corrective action, as part of CR 98-3744, to revise inservice Test (IT) 1030,
"40-Month Pressure Test of the Spent Fuel Cooling System," to comply with ASME Code,1986 Edition, no Addenda,Section XI, Paragraph IWA-5243, " Components With Leakage Collection Systems." The inspectors considered the planned corrective action appropriate to correct and prevent recurrence. Failure to adequately enmplete the Code VT-2 visual examination of the Units 1 and 2 spent fuel storage poolis a violation of T/S 15.4.2.B.1 and although it was licensee-identified, because of its repetitive nature it is being treated as an example of a cited violation (VIO 50-266/98021-04b(DRP);
50-301/98021-04b(DRP)) with no licensee response require E8.8 (Closed) LER 50-266/98028: * Missed surveillance required by Section XI pressure test program." This event was discussed in Section E1.2 of IR 50-266/98019(DRP);
50-301/98019(DRP) and dispositioned above in Section E8.6. No new issues were discussed in the LE E8.9 (Closed) LER 50-266/97023: 50-301/9702l: "Noncompliant emergency lighting for
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postulated Appendix R fires." This LER was discussed and dispositioned in Section E2.5 of IR 50-266/97010(DRS); 50-301/97010(DRS).
E8.10 (Closed) LER 50-301/97002: " Reactor coolant system branch connection stresses beyond design batis." On April 15,1997, the licensee identified that the Unit 2 reactor coolant system loop "B" resistance temperature detector branch connection could be stressed in excess of the design basis ASME Code allowable limits. The licensee determined that this resulted from an improperly performed design calculation associated with a 1987 piping support modification. The inspectors reviewed the records related to this issue and considered the docketed information to be accurate and comprehensive. The corrective actions were considered to be appropriate and included a recalculation of piping stresses and the relocation of piping supports to ensure that stresses were within Code allowable limits. This licensee-identified, non-repetitive failure to perform adequate design calculations is being treated as an NCV (NCV 50-301/98021-05(DRP)) of 10 CFR Part JC, Appendix B, Criterion Ill, " Design Control," in accordance with Section Vll.B.1 of the NRC Enforcement Polic E8.11 (Closed) VIO 50-266/97006-01b(DRP): 50-301/97006-01b(DRP): " Corrective actions for Appendix R equipment ventilation requirements." The inspectors verified the corrective actions described in the licensee's response letter, dated June 23,1997, to be reasonable and complete. No similar problems were identifie ,
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I IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R General Comments (IP 71750)
l 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 practice j
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The licensee's U2R23 outage goals were 166 person-rem and less than 100 personnel '
contamination events. As of December 22,1998, the sctual personnel exposure was more than 50 percent below the goal for that point in U2R23. The inspectors questioned ,
the radiation protection supervisor about this observation. He explained that on l November 2 the licensee changed from self-reading dosimeters (SRDs) to electronic dosimeters (EDs). The outage goal had been developed based upon exposure ]
i monitored by SRDs. Thus far, the licensee has found the EDs provide a much more l accurate indication of dose received than did the SRD The licensee was in the process of revising the outage dose goal downwards when questioned by the inspectors. The licensee was making the change in order to better monitor radiation worker performance and be able to make changes in performance, if needed. Without a meaningful basis for comparison, in this case a goal based upon SRDs but being measured using EDs, performance could easily be inadequately monitored or controlled. Subsequently, the licensee issued a new goal of 133 person-rem for personnel exposur l Conclusions '
i The licensee appropriately lowered the Unit 2 refueling outage 23 personnel exposure i goal to better monitor and control radiation worker exposur ,
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the ;
conclusion of the inspection on January 4,1999. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the '
inspection should be considered proprietary. No proprietary information was identifie PARTIAL LIST OF PERSONS CONTACTED Licensee
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Wisconsin Electric Power CompA M.E. Reddemann, Site Vice President R.G. Mende, Plant Manager J.R. Anderson, Operations Manger D.P. McCloskey, Maintenance Manager R.P. Farrell, Radiation Protection Manger -
V.M. Kaminskas, Regulatory Services and Licensing Manager C.R. Peterson, Director of Engineering J.G. Schweitzer, System Engineering Manager NRC B.A. Wetzel, Point Beach Project Manager, NRR
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l l INSPECTION PROCEDURES USED IP 37551: Onsite Engineering l ~ IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing ;
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IP 60705: Preparation for Refueling
IP 60710: Refueling Activities )
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IP 61726: Surveillance Observations -
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IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71714: Cold Weather Preparations *
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IP 71750: Plant Support Activities i IP 92901: Followup - Operations IP 92902: Followup- Maintenance IP 92903: Followup - Engineering 1 IP 92904: Followup - Plant Support l
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ITEMS OPENED, CLOSED AND DISCUSSED J Ooened 1 50-266/98021-01(DRP) IFl Plant's cold weather preparation program 50-301/98021-01(DRP)
50-266/98021-02(DRP) URI immediate operator actions i l
50-301/98021-02(DRP)
50-266/98021-03(DRP) NCV Potential common mode failure in 120-volt 50-301/98021-03(DRP) attemating current instrument power supplies 50-266/98021-04a(DRP) VIO Failure to complete system pressure tests 50-266/98021-04b(DRP) VIO Failure to adequately complete the Code VT-2 50-301/98021-04b(DRP) v;sual examination of the Units 1 and 2 spent fuel storage pool 50-301/98021-05(DRP) NCV Reactor coolant system branch connection stresses beyond design basis Closed 50-266/98009-07(DRP) IFl Evaluation of load to main steam piping from 50-301/98009-07(DRP) inadequate drains 50-266/97020-02(DRP) IFl Assess proceduralcontrols 50-301/97020-02(DRP)
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l 50-301/97006-01a(DRP) VIO Corrective actions for blocking device removal '
50-266/97013-01(DRP) VIO Failure to follow procedure for alarm response 50-301/97013-01(DRP)
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50-266/97013-03(DRP) VIO Procedural deficiencies cause valve mispositioning !
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50-301/97013-03(DRP) events 50-266/97005-01(DRP) eel Change to operation of motor-driven auxiliary 50-301/97005-01(DRP) feedwater pump was an unreviewed safety ;
question !
50-266/96015-02(DRP) VIO T/S full pressure test not done !
!
50-266/97006-01c(DRP) VIO Corrective actions for reactor coolant system drain- l down events I 50-266/96015-03a(DRP) VIO Appendix B, Criterion XVI, corrective actions 50-301/96015-03a(DRP) problem 50-266/97003-02a,b,c(DRP) VIO Crossover and condenser steam dump valves and component cooling water pump impeller cracks 50-266/97003-03(DRP) IFl AFW assumption validity in SW system calculation 50-301/97003-03(DRP)
50-266/97013-05(DRP) VIO Failure to calibrate maintenance and test 50-301/97013-05(DRP) equipment 50-266/97006-02(DRP) IFl Maintenance program improvement initiatives 50-301/9700d-02(DRP)
l 50-266/96015-03b(DRP) VIO Appendix B, Criterion XVI, corrective actions 50-301/96015-03b(DRP) problem 50-266/97021-03(DRP) IFl CCW treated as closed system without boundary 50-301/97021-03(DRP) checks 50-301/97001 LER Containment liner clearance not in accordance with plant design basis 50-266/96013 LER Potential common mode failure in 120-volt 50-301/96013 altemating current instrument power supplies 50-266/98021-03(DRP) NCV Potential common mode failure in 120-volt 50-301/98021-03(DRP) alternating current instrument power supplies 50-266/96019-05(DRP) VIO Inadequate corrective actions / main steam safety 50-301/96019-05(DRP) valve setpoint drift
-_ _
, ,
50-266/96015-03c(DRP) VIO Appendix B, Criterion XVI, corrective action 50-301/96015-03c(DRP) problem 50-266/98019-02b(DRP) eel Failure to complete system pressure tests 50-266/98019-02a(DRP) eel Failure to adequately complete the Code VT-2 50-301/98019-02a(DRP) visual examination of the Units 1 and 2 spent fuel storage pool 50-266/98021-04a(DRP) VIO Failure to complete system pressure tests 50-266/98021-04b(DRP) VIO Failure to adequately complete the Code VT-2 50-301/98021-04b(DRP) visual examination of the Units 1 and 2 spent fuel storage pool 50-266/98028 LER Missed surveillance required by Section XI pressure test program 50-266/97023 LER Noncompliant emergency lighting for postulated 50-301/97023 Appendix R fires 50-301/97002 LER Reactor coolant system branch connection stresses beyond design basis
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50-301/98021-05(DRP) NCV Reactor coolant system branch connection stresses beyond design basis
50-266/97006-01b(DRP) VIO Corrective actions for Appendix R equipment I 50-301/97006-01b(DRP) ventilation requirements l
piscussed i
! URI 50-266/98019-01(DRP) Licensee Procedure Adherence Guidance 50-301/98019-01(DRP)
I t
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LIST OF ACRONYMS USED AFW Auxiliary Feedwater I AOP Abnormal Operating Procedure AO Auxiliary Operator ASME American Society of Mechanical Engineers CCW Component Cooling Water CFR Code of Federal Regulations CO Control Operator CR Condition Report DOS Duty Operating Supervisor DSS Duty Shift Superintendent DRP Division of Reactor Projects EDs Electronic Dosimeters j eel Escalated Enforcement item
- F degrees Fahrenheit l IFl Inspection Followup Item IP Inspection Procedure IR inspection Report !
IWP installation Work Plan LER Licensee Event Report MOV Motor-Operated Valve NCV Non-Cited Violation
, NP Nuclear Power Business Unit Procedure
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NRC Nuclear Regulatory Commission OM Operations Manual OP Operating Procedure OS Operating Supervisor l PC Periodic Check l
QV Quality Verification l RHR Residual Heat Removal
,
RV Reactor Vessel !
l SFSP Spent Fuel Storage Pool SI Safety injection ;
j -SRDs Self-reading Dosimeters l
l SRO Senior Reactor Operator ;
l SW Service Water T/S
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Technical Specification ;
U2R23 Unit 2 Refueling Outage Number 23 j URI Unresolved item l VIO Violation l WMR Work Monitoring Report i WO Work Order '
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