IR 05000461/1998003
| ML20217G717 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 03/27/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20217G701 | List: |
| References | |
| 50-461-98-03, 50-461-98-3, NUDOCS 9804020500 | |
| Download: ML20217G717 (41) | |
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U.S. NUCLEAR REGULATORY COMMISSION l
REGION lll'
Docket No:
50-461 License No:
NPF-62 Report No:
50-461/98003(DRP)
Licensee:
lilinois Power Company
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Facility:
Clinton Power Station Location:
Route 54 West Clinton, IL 61727 Dater,:
January 23 - March 3,1998
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inspectors:
T. W. Pruett, Senior Resident inspector K. K. Stoedter, Resident inspector D. E. Zemel, lilinois Department of Nuclear Safety Approved by:
Thomas J. Kozak, Chief Reactor Projects Branch 4
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9904020500 980327 PDR ADOCK 05000461 O
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EXECUTIVE SUMMARY Clinton Nuclear Power Station, Unit 1 NRC Inspection Report No. 50-461/98003(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection.
Operations Control room operators intentionally deleted information from a control room computer
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screen in an attempt to maintain mental awareness. Although the line assistant shift supervisor (LASS) was aware of this practice, he failed to take action to address the situation. The actions of the LASS and the reactor operator (RO) were indicative of continued poor operator performance, a general disregard for main control room indications, and poor supervisory oversight (Section 01.1).
The inspectors identified that the corrective actions implemented failed to prevent another
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unmonitored increase in main control room (MCR) deficiencies and operator workarounds, even though both issues were the subject of a response to NRC Confirmatory Action Letter Rlli-97-001 (Section O2.1)
Operations and engineering personnel demonstrated poor knowledge of the breathing air
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system in that they believed the system had been abandoned in place and were unfamiliar with system operating parameters. Not using alternate compensatory methods to recharge the breathing air system bottles after identifying that the system was required to be maintained operable at all times demonstrated a nonconservative establishment of priorities for system restoration (Section O2.2).
Actions were not implemented to operate the service water traveling screens during cold
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weather in order to prevent ice blockage and a potentialloss of the ultimate heat sink. A delay in operating the traveling screens upon completion of a maintenance activity indicated poor oversight of restoring required plant systems to service by operations personnel. Implementation of procedural guidance to minimize ice blockage of the intake structure following the identification of the issue was delayed due to the poor prioritization of procedure revisions (Section O2.3).
l Implementing procedures for cold weather preparations were cumbersome in that they
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l were not easily identified and provided vague criteria for initiating actions. Numerous
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discrepancies with cold weather requirements were identified amongst the various cold weather procedures (Section O2.4).
Even though the licensee was required to replace service air intake filters and secure
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ventilation systems due to icing on February 8,1998, a requirement to verify the intake filters were free of obstructions during cold weather periods had not been added to system operating procedures or the area operator logs as of March 3,1998 (Section O2.4).
Several deficiencies were identified in the procedure change process which included the
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implementation of multiple one time procedure changes to address the same situatior, on
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4 out of 51 procedures, the lack of periodic reviews to determine if changes needed to be incorporated into the procedures, untimely procedure changes due to poor prioritization of procedure revisions, and inadequate performance of independent technical reviews and impact assessments. Collectively, the deficiencies signified that the licensee's corrective actions to improve procedure quality in response to Confirmatory Action Letter 111-96-013 have not been fully effective (Section O3.1).
Following an overload of the Division ll Emergency Diesel Generator (EDG), the licensee
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identified that non-licensed operators had not been trained on the remote operation of the EDGs since late 1992 or early 1993. In addition, some non-licensed operators were unaware of the significance of indications provided on the local EDG panels. After discovery of the inadequate training, actions to ensure qualified personnel were available to perform local manual operation of the EDGs were not immediately taken (Section 05.1).
Timely corrective actions were not implemented to prevent operations personnel from
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rendering both EDGs inoperable due to taking the maintenance switch for one EDG to the lockout position in preparation for surveillance testing while the other EDG was inoperable (Section 08.2).
Maintenance Provisions of the maintenance troubleshooting procedure were not implemented during
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testing of the Division 11 EDG kilowatt indication. Specifically, maintenance personnel did not have a procedure or test plan for performing specific tasks, the activities were not approved by operations personnel, tasks being performed were not documented as they occurred, the chronology of events did not specify all actions taken, electrical maintenance work practices were poor, and supervisory oversight was minimal (Section M1.2).
The briefing given prior to performing a special test procedure on the Division 11 EDG was I
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improved from previous briefings and included information on communications, self checking, safety, and lessons learned from other utilities (Section M1.3).
Enaineerina Engineering personnel did not recognize the significance of extreme outside air
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temperatures on EDG operability. After prompting by the NRC inspectors, an appropriate engineering evaluation was' performed (Section E1.1).
Design basis information involving ambient outside air temperature was not translated
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into specifications which effected the service life of EDG components, and resulted in the Division til EDG being inoperable when outside air temperatures exceeded 91F (Section E1.1).
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Design basis information regarding the proper electrical isolation between Class IE and
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non-Class IE components was not translated into a modification package for replacing the Division I and ll EDG annunciator power supplies. This resulted in improper electrical isolation between non-Class IE and Class IE EDG circuitry for approximately six years and created an unreviewed safety question which may have prevented the
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Division I and II EDGs from operating when outside air temperatures exceeded 91"F (Section E1.1).
No testing of resistance temperature devices (RTDs) within the diesel ventilation system
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was performed to demonstrate that the RTDs would perform satisfactorily in service even though the Updated Safety Analysis Report (USAR) clearly delineated the requirement (Section E1.2).
An adequate 10 CFR Part 50.59 safety evaluation was not performed to ensure that
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changes in the testing methodology for the diesel ventilation system did not constitute an unreviewed safety question. Specifically, changes were made to delete test requirements from procedures even though the USAR clearly specified the testing to be performed (Section E1.2).
The shift supervisor's review of condition report 1-97-12-221 involving inadequate testing
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of RTDs and the diesel ventilation system was poor and lacked intrusiveness in that it was not properly classified, it did not consider possible generic implications on other plant equipment, and it did not ensure that an appropriate tracking mechanism was in place to prevent an EDG from being returned to an operable status prior to resolving the issue (Section E1.2).
Plant Support During the Alert, the shift supervisor maintained an oversight role of activities in the
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control room and prompted actions when appropriate. The LASS controlled the activities of ROs and non-licensed operators. The shift supervisor used conservative decision making to activate the emergency response organization (ERO) in order to obtain additional resources to restore shutdown cooling (Gection P1.1).
The shift supervisor limited access to the MCR by assigning an individual the
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responsibility to prevent entry by non-essential personnel. This action significantly reduced the number of distractions in the main control room. Operations personnel demonstrated good use of emergency, off normal, and system operating procedures in the MCR (Section P1.1).
The licensee performed a critical assessment of ERO performance during the Alert.
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Deficiencies noted by the licensee included offsite notifications, activation of the technical support center (TSC), operation of the autodialer, control of field teams, communications between the TSC and the MCR, site wide announcements, use of ERO badges, and control of field samples (Section P1.1).
Minimum emergency plan staffing for on shift,30 minute, and 60 minute response was
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not met. Seven radiation protection and maintenance personnel were added to the on shift emergency planning minimum staffing requirements due to concerns regarding the ability to meet the manning requirements (Section P1.1).
Fire watch personnel failed to perform a tour of the Division 11 EDG room in order to
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evaluate the presence of transient combustible materials (Section F1.1).
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Report Details Summary of Plant Status The plant remained shut down throughout the inspection period. On January 22,1998, the operations department entered a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> stand down due to an increase in performance errors.
On February 13 operations personnel declared an Alert when shutdown cooling isolated due to the de-energization of the Division ll Nuclear System Protection System (NSPS) bus.
1. Operations
Conduct of Operations 01.1-Manioulation of Main Control Room Performance Monitorina System Computer Screens a.
Inspection Scope (71707)
The inspectors performed walk downs of the main control room panels to verify that indications accurately reflected current plant conditions.
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Observstions and Findinas During a panel walk down on January 21,1998, the inspectors noticed that one of the computer screens for the performance monitoring system appeared to be malfunctioning.
Specifically, the screen which was normally used to provide operating information (noun name description, current reading, and setpoint information) for various components had been blackened out such that the computer point and noun name description no longer appeared. The inspectors asked the "A" reactor operator (RO) about the status of the screen. The "A" RO responded that there was nothing wrong with the screen and that he had blackened out part of the screen because he was bored.
Following the discussion with the "A" RO, the inspectors remained in the control room to monitor actions taken to restore the computer screen. The inspectors noted that shift management, other licensed operators, and the shift technical engineer did not inquire about the abnormal screen or ask that the screen be returned to normal. The inspectors later leamed that the screen was restored to its normal configuration approximately two hours later when the day shift operations crew assumed the watch.
In discussions with plant management, the inspectors emphasized that the actions of operations personnel were indicative of continued poor operator performance, a general disregard for main control room indications, and poor supervisory oversight. Licensee management agreed with the inspector's assessment and initiated an operations stand i
down to discuss this event and several other recent events which had occurred in the operations department. Through the stand down, licensee management learned that this was not an isolated incident. Many operations crews stated that they had performed similar actions to maintain their mental awareness during times of limited plant activity.
Procedure 1401.01, " Conduct of Operations," Step 8.1.5.4, required the Line Assistant Shift Supervisor to be responsible for directing the licensed activities of the RO at the
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controls to ensure that the RO can adequately monitor and manipulate the controls. In j
addition, Step 8.1.7.7 d stated that the RO is responsible for monitoring computer screens, indicators, annunciators and records in order to detect unusual or abnormal trends. The failure of the line assistant shift supervisor to ensure that the RO was adequately monitoring the controls and the failure of the RO to appropriately monitor control room computer screens and indications was considered a violation of Technical Specification (TS) 5.4.1.a. Howover, because significant NRC enforcement action was taken for a programmatic breakdown in procedure adherence and the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600 were met, a Notice of Violation is not being issued (NCV 50-461/98003-01a).
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Conclusions The line assistant shift supervisor failed to adequately direct licensed activities and the reactor operator failed to monitor main control room CRTs in a safe and competent manner when a computer screen was blackened out in the main control room. These actions were indicative of continued poor operator performance, a general disregard for main control room indications, and poor supervisory oversight.
01.2 Operations Department Stand Down and Seminar On January 22,1998, the operations department declared a stand down due to several recent deficiencies involving TS usage, monitoring of control panels, and adhering to radiological boundaries. As a result of the stand down, the operations department performed an additional two day seminar on February 11 and 12, to discuss performance issues and to develop corrective actions for improvement.
Operational Status of Facilities and Equipment O2.1 Main Control Room Deficiencies and Operator Workarounds a.
Inspection Scope (71707)
The inspectors performed a review of main control room (MCR) deficiencies to determine if the licensee's corrective actions to reduce and track discrepancies had been effective following implementation of its response to Confirmatory Action Letter (CAL) Rlll 97-001.
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Observations and Findinas Procedure OSO-089," Operator Workarounds and MCR Deficiencies," defined an MCR deficiency as: "An equipment related problem either in the MCR itself or in the plant that has:
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A maintenance work request (MWR) written against it, and 2.
An associated MWR tag resides in the MCR, and 3.
The deficiency meets at least one of the following criteria:
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restricts operation of equipment from the MCR in accordance with the
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operating procedures, or masks or inhibits an operator's ability to determine and evaluate plant
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conditions from the MCR, or lights or extinguishes annunciators or other indicators in the MCR
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indicating an equipment problem."
On December 1,1997, the inspectors requested a list of known MCR deficiencies. The licensee provided a summary printout of 156 deficiencies,72 of which remained to be worked and 84 of which required post maintenance testing.
The inspectors performed a walkdown of the MCR and identified approximately 185 MWR tags located in storage bins, desk drawers, or on MCR panels. The inspectors compared the MWR tags in the MCR to the MCR deficiency list and determined that only 56 of the 185 MWR tags were associated with an item on the MCR deficiency list. The inspectors noted that 100 MCR deficiency list items did not have a MWR tag located in the MCR.
The inspectors considered this significant in that no identifiers existed for operations personnel to readily note a suspect indication.
The inspectors performed a review of existing MWR tags in the MCR and determined that severalitems met the Procedure OSO-089 criteria for a MCR deficiency. Subsequent to the inspectors observatiori, the licensee performed a review of MCR MWR tags and added approximately 30 deficiencies to the MCR deficiency list. However, not all deficiencies involving the plant radiation system were included in the MCR deficiency list even though they met the criteria for a MCR deficiency. Additionally, the inspectors noted several examples where multiple component deficiencies were specified under one MWR; however, the individual components were not tracked as separate MCR deficiencies.
During discussions with operations personnel, the inspectors were informed that the responsibility for implementation of the MCR deficiency program had been transferred from the operations department to the maintenance department in mid-November. Soon thereafter, the operations department individual who had been reviewing new MWRs for impact on MCR deficiencies returned to an operating shift crew. However, the individual who had been designated with responsibility of reviewing MWRs to determine which items were MCR deficiencies was unaware that he had been assigned the new task.
Consequently, for a period of approximately two weeks, no reviews were performed of newly initiated MWRs to determine if they should be assigned to the MCR deficiency list.
The inspectors considered the failure to ensure personnel responsible for identifying MCR deficiencies were informed of the newjob assignment an example of poor communications within the operations department.
During discussions with the maintenance manager, the inspectors determined that the maintenance department interpreted the criteria for a MCR deficiency differently than personnel in the operations department. Specifically, maintenance personnel did not view component deficiencies in the field which caused invalid annunciators or indications in the MCR to be a MCR deficiency. The maintenance department view was narrowly focused in that they believed a MCR deficiency was limited to actual component
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t deficiencies which originated within the MCR. The failure to ensure that maintenance and operations personnel used the same criteria in selecting MCR deficiencies is an example of poor communications between the operations and maintenance departments.
The inspectors periodically questioned operations personnel on the status of various MCR deficiencies (with or without MWR tags in the MCR) to dete.mine if they were aware that the deficiency existed or if they knew the reason for the deficiency. The inspectors noted a wide range of responses including: thorough knowledge of the deficiency, knowledge that a deficiency existed but not the reason for the deficiency, and a lack of knowledge regarding the existence of a deficiency. The inspectors determined that the variance in knowledge was attributed to the frequency of watch standing responsibilities, whether or not a MWR tag existed in the control room, the omission of an identifier on the MCR panel alerting the operator to the deficiency, and the omission of a MCR deficiency list in the MCR.
The inspectors also reviewed the operator workaround list. Fifteen items were specified on the operator workaround list. Operations personnel stated that items on the MCR deficiency list were not included on the operator work around list even if the discrepancy met the conditions to be on both lists. The inspectors discussed the operator workaround list with licensee management and determined that senior management was unaware that operator workarounds existed on the MCR deficiency list.
In mid-December, following discussions with the inspectors, operations personnel stated that they would retake responsibility for the MCR deficiency program, perform audits of the MWRs, compare deficiencies to the existing MCR deficiency list, develop a new methodology to identify MCR deficiencies on MCR panels, and identify operator workarounds which were listed on the MCR deficiency list.
On January 15,1998, the inspectors discussed the status of MCR deficiencies and operator workarounds with operations personnel. The inspectors were informed that a review to resolve the above mentioned discrepancies had not been initiated since the individual responsible for the review had been assigned to a unrelated Plan For Excellence team. In addition, the licensee had not initiated a condition report to document the discrepancies in the MCR deficiency and operator workaround programs.
The problems identified with the implementation of the program are of particular concern given the high visibility placed on oversight of the program following the September 5,1996, recirculation pump seal failure event, subsequent CAL, and development of the licensee's start-up readiness action plan and long term improvement plan. On December 9,1996, the licensee provided a response to CAL Rlll-97-001 which included specific provisions for a quarterly assessment of long term material deficiencies to ensure that corrective actions are being pursued aggressively and operational needs are clearly being met. At a minimum, the quarterly assessment was to address, in part, main control room deficiencies and operator workarounds. NRC Inspection Report No. 50-461/97014 documented that MCR deficiencies were receiving a high degree of management attention, were tracked continually, and that a means to identify, disposition, and track new deficiencies had been developed.
10 CFR Part 50, Appendix B, Criterion XVI, requires in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions,
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L deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause cf the condition is determined and corrective action taken to preclude recurrence. Following the August 1997 decision to delay plant start-up, oversight of MCR deficiencies deteriorated as emphasis was placed in improving performance in other problem areas. Consequently, the lack of effective oversight resulted in the inability to assure long lasting corrective actions were implemented to
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prevent recurrence of another unmonitored increase in MCR deficiencies and operator workarounds, a condition adverse to quality. The failure to implement effective corrective actions is a violation of 10 CFR Part 50, Appendix B, Criterion XVI. However, because significant NRC enforcement action was taken for corrective action program problems and the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600 were met, a Notice of Violation is not being issued (NCV 50-461/98003-02a).
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Conclusions The inspectors identified that the corrective actions implemented failed to prevent another unmonitored increase in MCR deficiencies and operator workarounds, even though both issues were the subject of a response to NRC CAL Rlll-97-001.
O2.2 Control Room Breathina Air (RA)
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Inspection Scope (71707)
The inspectors reviewed the operational status of the control room RA system in response to Division I and ll low pressure annunciators.
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Observations and Findinas l
On January 29,1998, at approximately 7:00 a.m., the inspectors noted that the Division I and ll annunciators were lit for control room RA due to header pressure decreasing to 400 psig and questioned on shift operations personnel to determine the status of immediate and compensatory actions. The line assistant shift supervisor stated that they j
were unable to recharge the control room RA bottles because the charging air
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compressor relief valve was inoperable and that MWR D79224 had been initiated on January 21 to repair the valve. On January 26, the Division 11 RA low pressure annunciator energized but operations personnel did not increase the priority for repair of the control room RA compressor relief valve.
Annunciator Response Procedures 5041.03-3A, " Low Pressure DIV I Breathing Air Bottles," and 5041.04-4A, " Low Pressure DlV ll Breathing Air Bottles," required operations personnel to recharge the depleted division's air bottles. The inspectors noted that action was not taken due to the faulty relief valve and questioned operations personnel to determine if additional compensatory measures had been established. The inspectors determined that: (1) engineering personnel had not been notified that the control room RA pressure was low on both divisions; (2) at least two shift supervisors had not reviewed the annunciator response procedure; (3) no actions were planned or taken to compensate for the inability to recharge the bottles; and (4) operations personnel and
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the system engineer incorrectly believed that the control room RA system had been abandoned in place.
At approximately 12:00 p.m. on January 29, the inspectors were informed by operations personnel that: (1) the control room RA system was required to be in service to provide sufficient air for personnel to egress from the main control room; (2) the minimum.
required pressure was 300 psig; (3) both Division I and 11 were approximately 385 psig; and (4) Procedure 3214.02, " Breathing Air," Section 8.1.4.1.2, required that if either division was less than 300 psig then recharge the air bottles.' The inspectors questioned
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At approximately 5:00 p.m. on January 29, the inspectors were informed by operations personnel that: (1) the previously provided information on the control room RA system was incorrect; (2) the minimum design pressure of 300 psig was based on supporting 7 personnel for 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> in the main control room; (3) the Division I air header pressure was 385 psig and the Division 11 air header pressure was 180 psig; (4) the system was required to be maintained during all modes of plant operation; and (5) no compensatory
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actions had been implemented to stage additional air packs or use a portable air
compressor to recharge the control room RA system bottles.
On January 29, following discussions with the inspectors, the licensee initiated a i
permanent procedure change via procedure deviation for revision (PDR) 98-0099 for Procedure 3214.02, which allowed the use of portable air compressors to recharge control room RA bottles and raised the minimum pressure for recharging the RA bottles
~ from 300 psig to 400 psig. On January 30, the PDR initiator forwarded the procedure to the shift supervisor. The shift supervisor stated that he requested that the shift resource manager perform the initial senior reactor operator review, however, the review was not completed until February 2. The shift resource manager stated that he returned the PDR to the shift supervisor for final approval; however, the PDR was not reviewed by a shift supervisor until February 8.
Because of the delay in approving the PDR, operations personnel did not use the available onsite portable air compressors to recharge the control room RA bottles. On January 31, following repair of the compressor relief valve, operations personnel recharged the RA system bottles. The inspectors determined that the failure to restore the control room header pressure between January 21 and 31,1998, was a violation of
. TS 5.4.1.a. However, because significant NRC enforcement action was taken for a programmatic breakdown in procedure adherence and the criteria in Section Vll.B.2,
" Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy),
NUREG-1600 were met, a Notice of Violation is not being issued (NCV 50 461/9800 01b).
On January 30, the inspectors questioned licensee personnel to determine the bases for the 300 psig minimum air pressure requirement for the control room RA system. Updated Safety Analysis Report (USAR) Section 6.4.4.2, " Toxic Gas Protection," specified that the control room RA system consists of two 14 bottle high pressure cascade breathing air
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personnel stated that a calculation did not exist wruch derived the minimum pressure requirement for the control room RA system or the basis for the 400 psig alarm set point.
Preliminary calculations performed by engineering personnel determined that the minimum pressure to be maintained in the control room RA system in order to support seven operators for six hours without recharging was 2100 psig. Additionally, engineering personnel stated that the 400 psig alarm set point was probably provided to warn personnel using the system that the air supply was nearly depleted. On February 21, the licensee approved PDR 98-0135, to raise the minimum pressure to recharge the control room RA system bottles from 400 psig to 2200 psig.
10 CFR Part 50, Appendix B, Criterion lil, " Design Control," requires, in part, that the design basis be correctly translated into specifications, drawings, procedures, and instructions. The failure to ensure design requirements for minimum control room RA system pressure were translated into plant procedures is a violation of 10 CFR Part 50, Appendix B, Criterion Ill. However, because significant NRC enforcement action was taken for a programmatic breakdown in procedure adequacy, adherence, and the crite'.ta in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages,"
of the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600 were met, a Notice of Violation is not being issued (NCV 50-461/98003-03a).
The inspectors noted two USAR discrepancies involving the control room RA system.
USAR Section 6.4.4.2 specified that control room personnel will be able to don respiratory equipment within two minutes; however, operations personnel were not required to demonstrate this ability. Additionally, Section 6.4.4.2 specified that training on the system would be provided biennially; however, operations personnel were not trained on the system. The licensee in..!ed Condition Report (CR) 1-98-02-435 to review the training related issues involving the control room RA system.
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Conclusions Operations and engineering personnel demonstrated poor knowledge of the control room breathing air system in that they believed the system had been abandoned in place and were unfamiliar with system operating parameters. The failure to use alternate compensatory methods to recharge the control room breathing air system bottles after identifying that the system was required to be maintained operable at all times demonstrated a nonconservative establishment of priorities for system restoration.
O2.3 Potential Ice Blockaae at Intake Structure a.
Inspection Scope (37551 and 71707)
The inspectc. reviewed provisions implemented by the licensee to prevent ice blockage of the intake structure during periods of extended shutdown.
b.
Observations and Findinas On January 13,1998, the inspectors noted that the shutdown service water temperature at the residual heat removal heat exchanger indicated 36 F. Because of the low temperature, the inspectors questioned control room operators to determine how the
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l facility prevented ice blockage at the service water intake during shutdown conditions.
Operations personnel stated that during plant operation, the warming line was placed in
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service to prevent ice blockage when intake temperature decreased below 40 F and that they were unaware of provisions to minimize ice blockage during shutdown conditions.
Engineering personnel informed the inspectors that the inability to utilize the warming line during shutdown conditions had been reviewed in Engineering Work Request (EWR) 96-08-11, initiated July 29,1996, in response to NRC Information Notice 96-36,
" Degradation of Cooling Water Systems Due to Icing." EWR 96-08-11 specified that during extended plant outages when the ambient temperature was less than 35 F, the traveling screens were operated in manual mode per Procedure 3210.01, " Screen Wash."
The continuous operation of traveling screens will stir up the water and prevent the advance of ice formation in the lake from west to east during extended plant outages concurrent with severe weather conditions for long periods. The inspectors questioned operations personnel and determined that the traveling screens were not being operated in the manual mode even though ambient temperature was below 35*F.
Procedure 3210.01, Section 8.2.4, " Cold Weather Operations," required that if the outside air temperature was less than 35 F, operations personnel should consider operating all screens in manual (or increase the frequency) to prevent pipe freeze up if the screen house temperature drops below 35 F and to prevent high differential pressure across the screens due to fish accumulating on screen surfaces. The inspectors noted that Procedure 3210.01 did not account for a loss of shutdown service water (ultimate heat sink) inventory due to ice blockage of the intake screens. Additionally, the actions in the procedure to " consider" operation of the intake screens in lieu of directing operation for specific plant conditions was not commensurate with the safety significance of a loss of the ultimate heat sink and was not consistent with EWR 96-08-11.
On January 14, operations personnel initiated CR 1-98-01-165 because of an inability to operate the traveling screens due to a malfunctioning differential pressure switch. The licensee repaired the differential pressure switch during the swing shift on January 14.
However, the screens were not placed into manual operation until the inspectors inquired about the status of the screens at the beginning of the day shift on January 15.
Operations personnel stated that an oversight by the operating shift resulted in the screens not being placed in service during the mid shift on January 15.
10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality be prescribed by documented instructions or procedures, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions or procedures. The fa";re to follow documented instructions in the EWR and operate the traveling screens to prevent ice blockage of the intake screens and a loss of the ultimate heat sink when ambient temperatures were less than 35"F is a violation of 10 CFR Part 50, Appendix B, Criterion V. However, because significant NRC enforcement action was taken concerning procedural compliance and the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600 were met, a Notice of Violation is not being issued (NCV 50-461/98003-04).
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In response to the inspectors observations and the licensee's subsequent review of NRC Information Notice 98-02, " Nuclear Power Plant Cold Weather Problems and Protective Measures," dated January 21,1998, the licensee provide letter Y-106980, "Frazil ice Recommended Actions for Condition Report 1-98-01-165," dated February 3,1998, to the operation's shift supervisors. The letter explained how frazilice is formed and the potential impact on plant operations. The licensee determined that with a complete blockage of the traveling screens at a normallake level and a shutdown service water flow rate of 20,000 g.p.m., it would take 86 minutes to reach the low ultimate heat sink level. With these conditions, the shutdown service water system could become inoperable during a station outage.
Letter Y-106980 recommended a prompt corrective action to revise Procedure 3210.01 to monitor lake water temperature indications, to continuously run all operable traveling screens, and to monitor water level in the circulating water screen house suction bay if:
(1) solid ice had not formed in front of the trash racks; (2) wind speeds were above 15 mph; (3) air temperature was 22*F or lower with a 2-3 F/hr decrease; and (4) lake water temperature was below 33*F on the raw water treatment monitors or 37*F on the shut down service water temperature monitors. On February 22, th< :1spectors determined that the licensee had not made the recommended revisions to Rocedure 3210.01 and questioned operations personnel on the status of the revision. Following discussions with operations management of February 23, the licensee implemented PDR 98-0144 to ensure the actions recommended by engineering personnel were implemented. The licensee stated that the delay in implementing the changes occurred because they believed the development of a cold weather operating procedure was imminent. As of the end of the inspection period, the cold weather procedure had not been approved.
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Conclusions Operations personnel were not knowledgeable of actions to minimize the potential for ice formation during shut down periods. A delay in operating the traveling screens upon completion of a maintenance activity indicated poor oversight of restoring required plant systems to service by operations personnel. A delay in implementing prompt corrective actions to provide guidance on minimizing ice blockage of the intake structure was an example of poor prioritization of procedure revisions.
O2.4 Cold Weather Preparations a.
Inspection Scope (71707)
The inspectors reviewed procedures associated with cold weather preparations, performed plant walkdowns, and interviewed operations, maintenance, and engineering personnel.
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Observations and Findinas The inspectors noted that implementing procedures for cold weather preparations were cumbersome in that they were not easily identified and provided vague criteria for initiating actions. During discussions with senior licensee management, the inspectors were informed that an action item had been assigned to the operations department in October 1997, to develop a single implementing procedure for cold weather
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requirements. The individual given responsibility to develop the new cold weather procedure was transferred from the operations department to the training department in December 1997. The partially completed procedure was given to the procedures group; however, a priority for further development was not assigned. Consequently, action to develop the procedure was not taken until the inspectors commenced a review of cold weather procedures and preparations on January 15,1998. At the end of the inspection period, a procedure had not been developed nor had all of the requirements imbedded in the multiple system procedures been implemented. The failure to develop a cold weather procedure is an additional example of poor prioritization of procedure revisions and development.
Because a single implementing procedure for cold weather preparations did riot exist, the inspectors requested that the procedure group provide a list of procedures implementing cold weather requirements. Procedure group personnel had to perform a word search on the computerized procedure database using the phrase " cold weather"in order to locate procedures specifying cold weather requirements. The inspectors reviewed the individual procedures and determined that an action to prompt operators to initiate the various procedural requirements did not exist.
Numerous discrepancies with cold weather requirements in various procedures were identified which involved: deleting a requirement to check heat trace operation from operator logs, not specifying heat trace circuits to be checked on electrical panels, not specifying temperatures for implementation of cold weather checks, providing incomplete guidance on items to be checked during cold weather tours, and not providing guidance to operations personnel prior to the onset of cold weather.
The inspectors reviewed the draft cold weather procedure and noted a requirement for chemistry personnel to inspect the sedimentation pond filter house heat trace once per shift. The inspectors determined that chemistry personnel were not implementing this requirement. The licensee subsequently determined that in 1992 the responsibility for equipment in the sedimentation pond filter house had been transferred from operations personnel to chemistry personnel. During the trmsfer, the requirement to check the heat trace was deleted from the operations checklist but not added to the chemistry checklist.
The licensee initiated CR 1-98-01-391 to resolve the issue.
On February 8, dense fog and low outside ambient temperature (25*F) caused icing to occur over the service air intake filters resulting in an incr 3 sed differential pressure across the filters. In addition, the fuel building, auxiliary building, turbine building, machine shop, and radwaste building ventilation systems also experienced increased differential pressures due to the icing. The icing resulted in the facility having to remove each service air compressor from operation to facilitate a filter replacement. In addition, the licensee had to secure ventilation systems as the differential pressure increased. The inspectors noted that increased cold weather checks for the service air compressors and the ventilation systems were not specified in system operating procedures. As of February 27, a requirement to verify the service air compressor intake filters and the ventilation systems free of obstructions during cold weather periods was not added to system operating procedures or the area operator logs.
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Conclusions implementing procedures for cold weather preparations were cumbersome in that they were not easily identified and provided vague criteria for initiating actions. The failure to develop a cold weather procedure after being directed by senior licensee management is an example of poor prioritization of procedure revisions and development.
Even though the licensee was required to replace the service air intake filters and secure ventilation systems due to icing on February 8,1998, a requirement to verify the intake filters and ventilation systems free of obstructions during cold weather periods was not added to the system procedures or area operator logs.
Operations Procedures and Documentation O3.1 Procedure Chanae Proaram a.
inspection Scope (71707)
The inspectors reviewed normal system operating and surveillance procedures to review the effectiveness of the licensee's procedure change process as delineated in Procedure 1005.07," Temporary Changes to Station Procedures and Documents."
b.
Observations and Findinas The inspectors reviewed the procedure change program and identified the following concerns: (1) of the 51 procedures changed in the last six months using the one time only procedure change process, four procedures contained multiple one time procedure changes to address the same situation; (2) one time only procedure changes were not
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i reviewed to determine if the change needed to be permanently addressed by the procedure; (3) procedure changes proposed by comment control forms or condition reports were untimely due to a lack of prioritization and a cumbersome review process; and (4) several independent technical reviews and impact assessments were inadequate.
Multiple One Time Procedure Changes Of the 51 procedures changed in the last six months using the one time only procedure change process (the temporary procedure deviation), four procedures contained multiple j
one time procedure changes to address the same situation. Specifically,
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Procedure 3303.01, " Reactor Water Cleanup (RT)," was changed four times within a 13 day period to address operating the system with both reactor recirculation loops isolated. The inspectors questioned members from the plant support services department regarding the acceptability of initiating multiple temporary procedure deviations (TPD) against the procedure since this action could allow personnel to circumvent the permanent procedure change process. Plant support services personnel stated that the initiation of multiple TPDs to address the same situation was not allowed by Procedure 1005.07, since Procedure Step 2.2.9 clearly defined a TPD as a change for one time use that was effective following approval by the shift supervisor.
Due to the multiple procedure changes initiated against Procedure 3303.01, the inspectors questioned operations personnel to determine if an additional procedure
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section was needed to describe how to operate the system using the bottom head drain as the only suction source. Initially, operations personnel stated that an additional procedure section was not needed, however, this decision was reversed when the procedure was reviewed by the assistant director - plant operations. At the conclusion of the inspection, personnel from the procedures group.were working on revising the RT procedure.
Procedure 3211.01, " Shutdown Service Water," was changed three times within a nine day period to support maintenance on Shutdown Service Water System 1B Isolation Valve 1SX0148. The licensee identified two additional examples of multiple TPDs to i
support maintenance activities. Procedure 9071.02, * Diesel Fire Pump Capacity Checks,"
was changed four times to perform post maintenance testing on a duplex filter because operations personnel continued to identify additional procedural enhancements which resulted in previous TPDs being disapproved. Procedure 8640.07, " Fixed Analog Area Radiation Monitor 1RI-PS844 (845) Channel Calibration," was changed twice in a three day period to delete the requirement to verify a trouble alarm was clear because the alarms were already locked in due to maintenance.
Plant support services personnel believed the initiation of multiple TPDs in support of maintenance activities was an acceptable practice. The inspectors noted that the current procedure change process did not allow TPDs to be made for maintenance purposes unless work was already in progress. The inspectors were also concerned that the licensee's current practice of allowing multiple changes for maintenance purposes may be communicating to the staff that it was acceptable to not follow the requirements of Procedure 1005.07 in certain situations.
The inspectors questioned the licensee to determine if a review was performed to assess whether or not conditions described in TPDs needed to be permanently incorporated into the procedure. The licensee stated that due to a lack of resources this type of review was not currently performed. However, the operations department planned to dedicate resources to perform this function as part the department's reorganization. The inspectors considered the lack of review a weakness since it prevented the timely identification of potential procedure inadequacies and could result in a diversion of resources from the operating crews in order to support unnecessary procedure changes.
Poor Prioritization and Review Process Effects Timeliness of Corrective Actions in addition to the procedure change program, two other methids can be used to initiate changes to procedures. Comment control forms (CCF) weru used to correct clerical errors or to suggest procedural enhancements which should be incorporated to improve the procedure. Changes to procedures were also initiated as corrective actions for CRs.
In September and Decembe 1996, both the NRC and the licensee's independent Safety Engineering Group identified dat information provided in CCFs which could have a significant impact on plant operation was not being incorporated into procedures in a timely manner due to a lack of prioritization. In response to this concern, the licensee developed a definition for what constituted a significant CCF. The licensee's current CCF backlog contained approximately 2600 items of which 16 were considered to M significant. The backlog of procedure revisions from CRs included over 150 in, m. The
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Inspectors reviewed portions of both backlogs and identified severalitems which were not considered significant by the licensee but had the potential to effect safe operation of the plant. For example, inspection Report No. 50-461/98004 documented that operations personnel were burdened with making a procedure change to Procedure 3312.01,
" Residual Heat Removal (RHR)," during an Alert, due to an inadequate procedure. A review of CCFs determined that a CCF had been written in May 1997 to address the situation encountered during the Alert. The RHR procedure changes were not seen as significant and were not incorporated even though the inadequate procedure had almost resulted in the operations department being in noncompliance with TS on two previous occasions.
Sections O2.3 and O2.4 of this report documented the untimely development of a cold weather procedure. Due to the lack of prioritization, no action was taken by the licensee until the inspectors performed a review of cold weather preparations.
On January 23,1997, licensee personnel identified a potential TS noncompliance during the performance of surveillance testing on the Division I or II Emergency Diesel Generator (EDG) while the other EDG was inoperable (see Section 08.2). In response to this event, operations personnel initiated CR 1-97-01 197 and proposed a change to Procedure 9080.01, " Diesel Generator 1 A/1B Operability," to prevent both EDGs from being inoperable during surveillance testing. Although EDG surveillance testing was performed every thirty one days, neither operations or procedures personnel recognized that Procedure 9080.01 needed to be revised prior to the next performance to ensure compliance with TS. The failure to recognize the significance of this procedure change resulted in the licensee taking nearly ten months to change the procedure.
Because of the items identified by the inspectors, the licensee initiated a review of the procedure backlog to ensure the appropriate significance was assigned to each request.
Performance of Independent Technical Reviews and Impact Assessments The licensee's current procedure change program allowed fourteen days between the initiation of the procedure change and the final review and approval of the change by licensee management. During the fourteen days, a safety evaluation was written to document why the proposed procedure change was technically acceptable. The safety evaluations were reviewed by an independent technical reviewer to ensure that the logic used in the safety evaluation was technically sound. Procedure changes were disapproved due to not approving the revision within fourteen days, due to technical inadequacies, or because of clerical errors. Once a procedure change had been disapproved, a member of the licensee's staff was required to perform an impact assessment to document the effect that the performance of work per the changed procedure had on plant equipment.
The inspectors determined that the performance of some independent technical reviews (ITR) and system impact assessments were inadequate. Specifically, ITRs were often performed by personnel that did not hold a current operating license and personnel performing impact assessments were not required to obtain engineering assistance. For example, operations personnelinitiated PDR 98-0115 to aid in maintaining the fill and vent of the RHR system in response to an Alert which occurred on February 13,1997.
Following the initiation of the PDR, TPD 98-0116 was initiated to ensure that operations
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personnel had procedural guidance in place in the event the situation which caused the Alert condition recurred. On February 19, operations personnel were informed that PDR 98-0115 was disapproved due to clerical errors which resulted in the changes made via TPD 98-0116 being invalid. This left the operators without approved procedures in this area should the conditions surrounding the Alert recur.
Licensee management agreed with the inspectors assessment in this area and made immediate changes to Procedure 1005.07 such that the impact of all disapproved procedure changes was required to be reported to the shift supervisor in a timely manner via a CR. The licensee also initiated a review of procedure changes disapproved during the last eight months to ensure that no unreviewed safety questions existed. The licensee planned to expand the scope of this review if problems were identified.
In response to CAL lil-96-013, the licensee committed to review the procedure process including the procedure use, revision, and backlog reduction programs to ensure that procedures were of high quality and were able to be used by the staff. Continued inspector and licensee identified examples of failing to follow procedures, the necessity to perform a large number of PDRs (75-100 per month), and the large backlog of procedure revisions (approximately 2750 excluding engineering revisions) indicated that the licensee's corrective actions to improve procedure use and quality have not been fully effective. Improvements to procedure usage and quality will continue to be reviewed as part of the NRC's 0350 Panel oversight of licensee improvement initiatives.
Licensee's Actions in Response to inspectors Concerns in response to the inspectors concerns, the licensee initiated CRs 1-98-02-231,-341, and -367. The licensee believed that many of the weaknesses identified above could be addressed by reorganizing the operations department and dedicating an individual to improve the coordination between the operations department and the procedures group.
Corrective actions for the remaining deficiencies were being developed at the conclusion of the inspection.
c.
Conclusions Several deficiencies were identified in the procedure change process which included the implementation of multiple one time procedure changes to address the same situation on 4 out of 51 procedures reviewed, the lack of periodic reviews to determine if changes needed to be incorporated into the procedures, untimely procedure changes due to poor prioritization of procedure revisions, and inadequate performance of independent technical reviews and impact assessments. When taken collectively, the deficiencies signified that the licensee's corrective actions to improve procedure quality have not been fully effective.
Operator Training and Qualification 05.1 Actions in Response to EDG Overloadina Event On February 11,1998, operations personnel overloaded the Division ll EDG during the performance of surveillance testing (see inspection Report 50-461/98004). In response to this event, personnel from the independent analysis group identified two additional
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concems regarding non-licensed operator (NLO) training and the quality of procedures goveming the operation of the EDGs.
On February 18, CR 1-98-02-215 was initiated to document that NLO training on the remote operation of the EDGs was discontinued which resulted in some NLOs not being qualified to operate the EDGs during a remote shutdown condition. As an interim measure, the shift supervisors were provided with a list of NLOs that were qualified to remotely operate the EDGs.
On March 2, the inspectors compared the list of qualified NLOs with the minimum shift coverage logs for the period of February 18-March 2 and identified that two shifts had no one qualified to remotely operate the EDGs, thirteen shifts would have had no one available to remotely operate the EDGs once the fire brigade was staffed, and that the operations department may not have met the requirements specified in Emergency Plan Table 2-1, "Clinton Power Station Minimum Staffing."
Table 2-1 required that two NLOs be available to diagnose and mitigate an emergency condition, that one individual be available for on shift emergency communications, and that five personnel be designated for fire brigade response. Fire brigade personnel may be filled as a collateral assignment. Each operating crew included four NLOs. The licensee frequently assigned three NLOs collateral duties as fire brigade members and one NLO as the emergency communicator for offsite notifications. If the licensee had a fire resulting in an emergency classification, the potential existed for no NLos to be available to diagnose the emergency condition. The determination of whether the operations department was meeting the requirements specified in Table 2-1 was considered an Unresolved item (URI 50-461/98003-05).
The independent analysis group also identified that Procedure 4003.01, " Remote Shutdown," provided incorrect information regarding the upper limit on EDG output voltage while the EDG was supplying the Class IE busses. To ensure that the voltage limits remained within specifications, a caution tag was placed on the Division I EDG local voltage control switch until the procedure could be revised.
Miscellaneous Operations issues (92901)
O8.1 (Closed) Inspection Follow-up Item 96006-02: Implementation of corrective actions in response to having both trains of control room ventilation inoperable. The inspectors verified that the licensee's proposed corrective acticns were implemented. No concerns were identified.
08.2 (Closed) Licensee Event Report (LER) 50-461/97-002: Failure to complete TS 3.8.2 limiting condition for operation required action B.4. On January 23,1997, operations personnel initiated CR 1-97-01-197 due to the failure to declare the Division i EDG inoperable when required. Procedure required that the EDG maintenance switch to be placed in the lockout position in order to perform prestart checks (e.g. bar over the EDG).
However, operations personnelidentified that if the maintenance switch for the Division I or 11 EDG was taken to lockout to perform prestart checks while the Division ll or i EDG was inoperable the actions would result in both EDGs being inoperable which was prohibited by TS 3.8.2, "AC Sources - Shutdown."
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O in response to this event, the licensee initiated a revision to Procedure 9080.01 to remove the requirement to bar over the Division I or 11 EDG if the other EDG was inoperable with the plant in Mode 4 or 5. The inspectors reviewed the licensee's implementation of this corrective action and found it took approximately ten months to change a procedure which was performed every thirty one days (see Section O3.1).
Because of the delay :n making the procedure change, the maintenance switches for the EDGs were unnecessarily placed in the lockout position approximately eighteen times between January 1997 and February 1998. Neither of the EDGs would have started on a valid start signal with one of the EDGs inoperable and the other EDG's maintenance switch in the lockout position.
The failure to implement corrective actions to prevent both EDGs from being rendered inoperable is considered a violation of 10 CFR Part 50, Appendix B, Criterion XVI.
However, because this violation was based upon activities prior to the events leading to the current extended p! ant shutdown and satisfies the criteria in Section Vll.B.2,
" Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy),
NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98003-06).
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments (62707 and 61726)
Portions of the following maintenance and surveillance activities were observed or reviewed by the inspectors:
-Procedure 9080.01 Diesel Generator 1 A/18 Operability-Procedure 9082.02 Offsite Voltage Verification-Procedure 2800.89 Diesel Generator IB Metering Troubleshooting Test Procedure-MWR D79417 Troubleshooting of Division ll EDG Kilowatt Indication Observations made during the performance of Procedure 9080.01 were the subject of a specialinspection and were documented in inspection Report 50-461/98004. Comments on other specific work activities are discussed below.
M1.2. Division 11 EDG Kilowatt (KW) Indication Troubleshootina a.
Inspection Scope (62707)
The inspectors observed troubleshooting activities on the Division il EDG KW indication in accordance with MWR D79417.
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Observations and Findinos On February 12,1998, the inspectors observed the performance of troubleshooting activities on the Division 11 EDG KW indication and noted several discrepancies. The inspectors questioned maintenance supervision involved in the activity to determine the results of the calibration test on the Division 11 EDG KW meter and were informed that the
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meter had failed the calibration test. During a job site review of the MWR, the inspectors noted that the Division 11 EDG KW meter had successfully passed the calibration test.
The inability to explain the status of the calibration indicated a poor awareness of the maintenance activity by electrical maintenance supervision. Following the satisfactory performance of loop and instrument testing, the licensee revised MWR D79417 to include job step SA, " Investigate / Troubleshoot to determine the cause of the problem."
Procedure 8170.06, " Maintenance Troubleshooting," required that the line assistant shift supervisor or shift supervisor approve troubleshooting activities and that a chronology of troubleshooting steps and observations of component and system operation be recorded.
The inspectors questioned maintenance personnel to determine the procedure or test plan in use. Maintenance personnelinitially stated that Procedure 8801.01, " Instrument Calibration," and 8801.02, " Loop Calibration," were being used to perform troubleshooting activities, however, they were unable to identify the applicable sections in use. In addition, the inspectors noted that Procedures 8801.01 and 8801.02 had both been completed earlier the same day. The inspectors noted that: (1) the line assistant shift supervisor or the shift supervisor had not approved the commencement of troubleshooting activities; (2) the chronology of troubleshooting steps had not been documented as they occurred; (3) there were no detailed instructions in the MWR to support the testing being performed; and (4) maintenance personnel performing the task were not aware of a test plan which authorized the combination of selected portions of the two procedures.
During a subsequent review of the MWR, the inspectors noted that maintenance personnel added a statement after completion of testing which indicated that station engineering personnel directed that a voltage / current input be injected at the Division 11 EDG breaker to simulate plant conditions and to follow local meters with main control room meters. The specific test points used during the activity were not described in the MWR.
The inspectors observed exposed energized electrical wires taped to the floor with test leads used to input signals from the Variac output to the Division 11 EDG breaker. The inspectors considered this a poor maintenance work practice.
The inspectors considered the control of troubleshooting activities weak in that maintenance personnel were not aware of procedures or test plans for performing specific tasks, the activity was not approved by the line assistant shift supervisor or the shift supervisor, tasks being performed were not documented as they occurred, the chronology of events did not specify all actions taken, electrical maintenance work practices were poor, and supervisory oversight was minimal. The failure to implement the provisions of the licensee's maintenance troubleshooting procedure is a violation of TS 5.4.1.a. However, because significant NRC enforcement action was taken conceming procedural compliance and the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy
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Conclusions Control of troubleshooting activities was weak in that maintenance personnel were not aware of procedures or test plans for performing specific tasks, the activity was not approved by the line assistant shift supervisor or the shift supervisor, tasks being performed were not documented as they occurred, the chronology of events did not specify all actions taken, electrical maintenance work practices were poor, and supervisory oversight was minimal.
M1.3 Briefina for Performance of Troubleshootina Test on the Division 11 EDG On February 27,1998, the inspectors observed the briefing given prior to the performance of Procedure 2800.89," Diesel Generator IB Metering Troubleshooting Test Procedure." The briefing included important information on the purpose of the test, communications, safety, self and peer checking, lessons learned by other utilities, and actions to be taken if any contingencies were to occur. The inspectors concluded that the briefing was an improvement from past observations.
M8 Miscellaneous Maintenance issues (92903)
M8.1 (Closed) Notice of Violation 50-461/96006-03: Inadequate job preparation for reactor water cleanup system maintenance resulted in inoperable leak detection instruments.
The licensee's corrective actions included briefing responsible personnel on the event and labeling all roof / floor plugs and doors which, if removed, could impact the operability ofleak detection equipment. The inspectors performed an audit of several plugs and doors and found no deficiencies.
Ill. Enaineerina E1 Conduct of Engineering E1.1 Inadeauate Desian of Diesel Generator Ventilation System Results in Licensee Operatina Outside Desian Basis a.
Inspection Scope (37551)
Through a review of USAR Section 2.3.1.1, " General Climate," the inspectors determined that the extreme outside air temperatures experienced near the facility were between -22'F and 112'F. The inspectors discovered that the VD fans were designed to maintain the temperature of the EDG rooms between 65"F and 130'F provided that i
outside air temperatures remained between -2'F and 96'F. Since the -22'F to 112'F temperature range exceeded the -2'F to 96 F range, the inspectors questioned j
engineering personnel to determine the impact of the differing temperature extremes on
the operability of the VD system and the EDGs.
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Observations and Findinas Summary of Inspectors Concerns Engineering personnelinitially informed the inspectors that the potentialimpacts of the-22*F to 112"F temperature band did not need to be considered because the VD system had been designed based upon criteria listed in the American Society of Heating, Refrigeration, and Air Conditioning Engineers Fundamentals Handbook,1972 Edition.
This edition stated that temperatures in the area around the facility would only be less than -2'F or greater than 96*F for approximately one percent of the year. However, the inspectors explained that the impact of the temperature extremes needed to be evaluated because: (1) outside air temperatures greater than 96*F could impact the service life of EDG components not qualified for operation at increased temperatures; and (2) outside air temperatures less than -2*F could result in increased horse power consumption by the VD fans and thus increased EDG loading.
Evaluation of Warmer Temperature Concern Based on the inspectors prompting, engineering personnel performed calculations to determine the temperature extremes' effects on the EDGs. The results were as follows:
Engineering calculation IP-M-0448, " Diesel Generator Room Temperature Evaluation at Extreme Maximum Outside Air Temperature," evaluated the potentialimpacts on the VD system and on the EDGs when outside air temperatures exceeded 96*F. On July 24, engineering personnel determined that the air temperature inside the EDG rooms would remain below 130'F, as required by USAR Section 9.4.5.1, if outside air temperature was less than 102.7'F for Divisions I and 11 and less than 104'F for Division 111. When considering the extreme maximum outside air temperature of 112*F, EDG room temperature was calculated to be approximately 140 F. Engineering personnel documented the inability to maintain the temperature in the EDG rooms less than 130*F under these conditions as required by the USAR in CR 1-97-07-250. Given this temperature condition, the licensee began evaluating EDG operability.
On August 21, engineering personnel discovered that calculation IP-M-0448 was nonconservative and initiated CR 1-97-08-204. Specifically, testing information in Illinois Power Letter Y-96194 indicated that components located inside the EDG control panels were subjected to an additional 23*F temperature rise during EDG operation. The temperature rise was attributed to heaters located inside the panels. This additional 23 F temperature rise resulted in the maximum air temperature inside the control panels reaching 163"F instead of the previously believed 140 F-. Based upon this new information, engineering determined the temperature inside the EDG panels would only remain below 140"F (maximum temperature for EDG operability) when outside air temperatures were less than or equal to 91 F.
In order to support long-term EDG operability at the increased EDG room and panel temperatures, engineering personnel enlisted the help of several contractors over a three week period in order to qualify all EDG components for operation at 140'F for twelve hours. The licensee believed a twelve hour limit was conservative since historical temperature data showed that the outside air temperatures between 104"F and 112*F were experienced for only 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> in the last 50 years. All components located inside
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the EDG control panels, except for the EDG annunciator power supplies, were qualified at temperatures of 165'F for 30 days. The EDG annunciator power supplies were qualified only for temperatures up to 130*F.
Warmer Temperature Effects on Division lil EDG Components Although engineering personnel were able to qualify most of the EDG components for operation at higher temperatures, they determined that temperatures greater than 140 F would potentially result in the Division 111 EDG annunciator power supply and horn experiencing a low impedance fault. This low impedance fault could cause an EDG control power failure due to inadequate fuse protection between the annunciator power supply and the EDG control power circuitry. A loss of control power would impact the ability to start and stop the EDG, to crank the engine, and to perform manual engine speed control. In addition, EDG protective features such as EDG undervoltage, safety shutdown, local alarms, and the main control room EDG trouble alarm would be disabled.
On August 26, temporary modification 97-076 was installed as part of the immediate corrective actions for CR 1-97-08-204. This temporary modification removed the doors from the Division 111 EDG Control Panel 1E22-S0018/C to allow the air inside the EDG control panel to mix with the air inside the EDG room such that the panel internal temperature would remain at or below 140 F in the case of extreme temperatures. By maintaining the temperature at or below 140"F, the possibility of a low impedance fault occurring was minimized. Long-term corrective actions included installing electrically coordinated fuse protection via engineering change notice (ECN) 30411 and MWR D50589 to prevent low impedance faults from occurring. The licensee planned to implement the ECN and the MWR as soon as plant conditions allowed. The failure to establish measures to ensure that design requirements for both inside and outside ambient air temperatures were correctly translated into specifications for the EDGs was considered a violation of 10 CFR Par 150, Appendix B, Criterion Ill. However, because
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this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy). NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98003-03b).
Evaluation of Control Panel Circuitry for the Division I and II EDGs On August 29, engineering personnel determined that: (1) the Division I and 11 EDG annunciator power supplies were not Class IE components; (2) the annunciator power supplies for the Division I and II EDGs were not properly electrically isolated; and (3) the control power circuits were susceptible to the same type of low impedance fault failure previously discovered on the Division lll EDG. CR 1-97-09-201 was initiated to document the discovery of the non-Class IE components.
As part of the root cause investigation for CR 1-97-09-201, the licensee identified that the previously installed Division I and 11 Topaz annunciator power supplies (Class IE) were replaced with Ronan power supplies (non-Class IE) on February 20,1991, and January 29,1992, via modification E-006. The licensee's review of the modification in September 1997, determined that engineering personnel documented a possible problem j
with the installation of the Ronan power supplies on July 9,1986, during the
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I interdisciplinary review for modification E006. The interdisciplinary review stated that several of the new power supplies, including the power supplies installed in the Division I and 11 EDG control panels, needed to be qualified as Class IE components. However, if the power supplies were unable to be qualified, then engineering personnel needed to consider the installation of double fusing to ensure adequate electricalisolation between the non-Class IE power supply and the remaining Class IE circuitry present in the control panel.
The licensee determined that the comment made during the interdisciplinary review had not been resolved prior to installing the power supplies in the EDG control panels. The inspectors considered the failure to resolve the comment significant in that a new EDG failure mechanism was created when the Class 1E power supply was replaced with a non-Class 1E power supply without adequate fuse protection. Specifically, when considering the impact of the temperature effects and the improper electricalisolation between the annunciator power supply (non-Class IE) and the EDG control power (Class IE) the possibility for an equipment malfunction of a different type than any previously evaluated in the USAR was created.
Updated Safety Analysis Report Section 8.3.1.4.1.4, " Electrical Isolation," states that non-Class IE associated components are electrically isolated from the Class IE system by an acceptable isolation device except where justified by analysis. The licensee determined that a justification for the inadequate electricalisolation did not exist. The failure to establish measures to ensure that design requirements for electrical isolation between Class IE and non-Class IE components were correctly translated into specifications and instructions for modifying the annunciator power supplies for both the Division I and 11 EDGs was considered an additional example of a violation of 10 CFR Part 50, Appendix B, Criterion Ill. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98003-03c).
Corrective Actions for Warmer Temperature Concerns Engineering personnel planned to resolve the improper electrical isolation concerns by installing a qualified current limiting fuse and fuse block between the Class IE and non-Class IE portions of the circuitry via ECNs 30294 and 30410 for the respective EDGs. The ECNs for the respective EDGs were installed on September 20 and December 19,1997.
The circuits for other Class IE panels which contain Ronan power supplies were reviewed to ensure adequate electricalisolation. No other deficiencies were identified by the licensee. Procurement engineering performed a search of other engineering / plant change documents which may have installed the same non-Class IE power supply and identified that no other design change documents had been issued which used the same type of Ronan power supply.
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t Evaluation of Colder Temperature Concems Engineering personnel evaluated the effects of extreme cold temperatures and determined that at temperatures of-22*F, the horse power for the Division I and 11 VD fans willincrease but would remain below the rated horse power stated on the equipment nameplate. The horse power for the Division ll1 VD fan was expected to be slightly higher than the horse power given on the nameplate however, this was acceptable based on the fact that as temperatures decrease the acceptable horse power rating increases. The increase in VD horse power had little effect on EDG loading due to the margin present in the licensee's EDG loading calculations.
c.
Conclusions Engineering personnel did not recognize the significance of extreme outside air temperatures on EDG operability. After prompting by the NRC inspectors, an appropriate engineering evaluation was performed.
Design basis information involving ambient outside air temperature was not translated into specifications which effected the service life of EDG components and resulted in the Division lli EDG being inoperable when outside air temperatures exceeded 91*F. In addition, design basis information regarding the proper electrical isolation between Class IE and non-Class IE components was not translated into a modification package for replacing the Division I and 11 EDG power supplies. This resulted in improper electrical isolation between non-Class IE and Class IE EDG circuitry for approximately six years which may have prevented the Division I and 11 EDGs from operating when outside air temperatures exceeded 91*F.
E1.2 Review of Diesel Ventilation System Testina a.
Inspection Scope (37551 and 62707)
The inspectors reviewed the following documents to ensure that all portions of the VD system were appropriately tested.
- PCIVDM030 Calibration of EDG Room 1A Supply Fan 1 A Damper Temperature Indicator-PEMVDA012 Preventive Maintenance for Motor Operator on outside Air Damper 1VD01YA-Procedure CPS 8801.03 Controller Calibration-Procedure CPS 8452.10 Hydramotor Preventive Maintenance b.
Observations and Findinas The safety-related por1 ion of a typical VD train included a resistance temperature device (RTD), a temperature controller, and two hydramotors which were used to control the position of their respective damper. During VD system operation, the RTD sensed the air temperature at the exhaust of the VD fan and sent a corresponding signal to the temperature controller, in turn, the temperature controller sent a signal to the hydramotors which repositioned the dampers to ensure that the air entering each EDG room remained at 70*F.
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The inspectors reviewed the procedures and preventive maintenance (PM) activities listed above and determined that testing described in these documents was inadequate in that only the temperature controller and the hydramotors were tested. Updated Safety Analysis Report Section 7.3.1.1.12.7.1, " Diesel Ventilation instrumentation and Controls Sensor Check," states that sensors required for sensing diesel room ambient temperature were tested in the following ways:
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by perturbing the monitored variable; by introducing and varying the substitute input to the sensor of the same nature as
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the measured variable; or by monitoring the parameter through other accurately calibrated instruments and
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comparing the output of sensors in use with the output of a calibrated instrument.
Through discussions with maintenance planning personnel, the inspectors learned that the RTDs contained in the VD system had not been tested since the completion of startup testing in the mid-1980's.10 CFR Part 50, Appendix 8, Criterion XI, " Test Control," states
"a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptable limits contained in applicable design documents. The test program shall include operational tests during nuclear power plant operation of structures, systems, and components. The failure to test the RTDs contained within the VD system using a method stated in USAR Section 7.3.1.1.12.7.1 was considered a violation of 10 CFR Part 50, Appendix B, Criterion XI. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98003-07).
The inspectors also identified that channel checks to ensure the temperature sensed at the RTD resulted in the proper damper positioning were not performed. Updated Safety Analysis Report Section 7.3.1.1.12.7.3, " Channel Checks," stated "after checks have been proven to be satisfactory at the module level, each channelis checked and monitored for satisfactory operation." The licensee reviewed the PM and procedure history for the VD system and determined that testing of each VD channel was changed from a loop calibration to a calibration of the controller on November 23,1990. Although a 10 CFR Par 50.59 evaluation was completed, the evaluation was inadequate in that it failed to recognize the change in testing methodology as a change in a procedure described in the USAR. Due to the lack of recognition, the proposed changes in testing methodology were not reviewed to ensure that an unreviewed safety question did not exist.
10 CFR Part 50.59 states, in part,"the licensee shall maintain records of changes in procedures to the extent that these changes constitute changes in procedures as described in the safety analysis report. These records must include a written safety evaluation which provides the bases for the determination that the change does not involve an unreviewed safety question." The failure to perform a written safety evaluation to ensure that the change in VD testing methodology did not involve an unreviewed safety question was considered a violation of 10 CFR 50.59. However,
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because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98003-08).
On December 15,1997, maintenance planning personnelinitiated CR 1-97-12-221 to document the lack of RTD and channel testing for the VD system. The inspectors reviewed the shift supervisor's evaluation of the CR and determined that the evaluation was poor and lacked intrusiveness in that: (1) it did not appropriately classify the CR; (2) it did not consider possible generic implications on other plant equipment; and (3) it did not ensure that an appropriate tracking mechanism (limiting condition for operation, mode restraint, operability determination) was in place to prevent an EDG from being returned to service prior to resolving the issue described on the CR. Operations management concurred with the inspectors assessment of the CR review. In response to the inspectors concerns, the RTD and channel testing issues described in the CR were entered as a mode restraint to ensure that the issues were resolved prior to returning an EDG to operable status.
On December 18, the Corrective Action Review Board upgraded the classification of CR 197-12-221 to significant. At the conclusion of the inspection, licensee personnel had taken action to resolve the testing deficiency and had satisfactorily performed testing on the required systems.
c.
Conclusions Testing of resistance temperature devices within the diesel ventilation system was not implemented as part of the test control program. A 10 CFR Part 50.59 safety evaluation to ensure that changes in the testing methodology for the diesel ventilation system did not constitute an unreviewed safety question was not performed. The shift supervisor's review of CR 1-97-12-221 involving inadequate RTD and VD system testing was poor and lacked intrusiveness in that it was not properly classified, it did not consider possible generic implications on other plant equipment, and it did not ensure that an appropriate tracking mechanism was in place to prevent an emergency diesel generator from being returned to service prior to resolving the issue described on the CR.
E8 Miscellaneous Engineering issues (92903)
E8.1 LClosed) LER 50-461/97-001 and 10 CFR Part 21 Report No. 21 97-003: Failure of nuclear fuel supplier to analyze turbine pressure regulator downscale failure event in the off-rated condition results in operation in an unanalyzed condition. The licensee reported that the nuclear fuel supply vendor had supplied a non-conservative power-dependent operating limit for the minimum critical power ratio (MCPR) which was used to monitor the reactor during fuel cycle six. The licensee stated that there were several occasions during fuel cycle six where the reactor was operated in a condition such that the MCPR operating limit was less than allowed by TS 3.2.2, " Minimum Critical Power Ratio," for greater than two hours. No immediate corrective actions were necessary since the plant was in a shutdown condition when the Part 21 was issued. The licensee had taken actions to ensure that the correct MCPR information was implemented in the core performance monitoring computer prior to commencing fuel cycle seven. This
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non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.I of the NRC Enforcement Policy (NCV 50-461/98003-09).
E8.2 (Closed) LER 50-461/97-022: Design of Diesel Generator Ventilation Subsystems Outside Design Basis as a Result of Failure to include Minimum and Maximum Outside Air Temperature Extremes Due to Design Error. Section E1.1 of this report documents the inspectors' review of the issues in the subject LER and therefore, this item is considered closed.
IV. Plant Support P1 Conduct of EP Activities P.1 Emeraency Response to Plant Alert l
a.
Inspection Scope (71750 and 93702)
The inspectors reviewed the licensee's response to the plant Alert involving a loss of shutdown cooling on February 13,1998. Additional information regarding the loss of shutdown cooling event is contained in NRC inspection Report 50-461/98004.
b.
Observations and Findinas On February 13,1998, at 3:41 a.m., a loss of the Division 11 NSPS bus resulted in a loss of the RT system and shutdown cooling flow. The shift supervisor evaluated the plant
conditions and declared an Alert at 4:11 a.m. under emergency classification 13.6,
" Judgement of Individual With Command Authority."
I Reactor water cleanup flow was established as an alternate source of shutdown cooling j
at 6:24 a.m. and the shutdown cooling mode of the RHR system was restored at
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9:44 a.m. The licensee terminated the Alert at 10:04 a.m. The licensee identified several deficiencies during the post event critique process. The observations made by the licensee indicated an improvement in the ability to assess the performance of the emergency response organization (ERO).
Control Room Activities The shift supervisor maintained an oversight role of activities in the control room and prompted actions when appropriate. The line assistant shift supervisor (LASS) controlled the activities of ROs and NLOs. The inspectors determined that the shift supervisor used conservative decision making to activate the ERO in order to obtain additional resources to restore shutdown cooling.
The inspectors determined that the shift supervisor limited access to the main control room by assigning an individual the responsibility to prevent entry by non essential personnel. This action significantly reduced the number of distractions in the main control room. The inspectors noted good use of emergency, off normal, and system operating procedures ir, the main control room.
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Emergency Notifications The licensee determined that the NLO assigned to make initial notifications was unsure of his duties for making offsite notifications. The shift technical advisor (STA) was required to relieve the NLO and perform the initial offsite notifications. Emergency Plan Implementing Procedure (EPIP) EC-07, " Emergency Plan Notification," Section 4.1.3 specified that the responsibility for completing notifications to the State and NRC should not be assigned to the STA. The inappropriate use of the STA to perform off site notifications was previously documented in NRC Inspection Reports 50-461/96010 and 97002 and indicates that the corrective actions for this deficiency were ineffective.
The use of the STA during following an emergency classification is considered an Unresolved item (URI 50-461/98003-10).
At 8:30 a.m., the licensee identified that the initial Nuclear Accident Reporting System (NARS) Form contained incorrect information for wind direction because the ND-6685 computer had stopped updating the buffer computer on February 12 at 1:50 p.m. The buffer computer provided meteorological, area radiation, and process radiation monitoring data to the NRC via the Emergency Response Om System (ERDS), to the Illinois Department of Nuclear Safety (IDNS), and to ths # nergency Operations Facility (EOF).
Upon discovery, the licensee rebooted the ND-6685 computer. Following the reboot, the computer commenced an update of all archived information which had been collected since the ND-6685 comouter stopped updating on February 12. One minute of update time was required for es ery nine minutes of archived data. As a result, approximately two hours elapsed between the time the discrepancy was identified (February 13 at 8:30 a.m.)
and the time current radiological and meteorological information was transmitted to the NRC, IDNS, and the EOF.
10 CFR Part 50.72(a)(4) requires, in part, that the licensee activate the ERDS as soon as possible but net later than one hour after declaring an emergency class of Alert or higher.
The inability to transmit current radiological and meteorological data within one hour of declaring an emergency classification is considered an Unresolved item (URI 50-461/98003-11).
Based on discussions with the licensee, the inspectors noted that: (1) the ND-6685 l
computer had experienced several hardware problems in the past, however, CRs describing the separate failures were not documented; (2) the failure on February 12, was due to an individual not rebooting the ND-6685 computer following the completion of an l
update to the system; (3) a procedure for performing the update on February 12 did not l
exist; (4) a failure of the ND-6685 computer does not provide an alarm and frequent l
l monitoring of the system was not performed to detect a failure; and (5) extended periods l
l of time may have existed when the licensee did not possess the capability to transmit l
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radiological and meteorological data to the NRC, IDNS, or EOF. The licensee's l
corrective actions to improve the reliability of the ND-6685 computer will be reviewed I
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during a future inspection (IFl 50-461/98003-12).
EPIP EC-07, Section 4.3, " Follow up Notifications to Key Offsite Agencies," required that notifications to IDNS be made over the commercial telephone at least once per hour following the issuance of the last NARS Form and after any change in command
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authority. The licensee identified that a follow-up message was not relayed to the IDNS for a change in command authority from the shift supervisor to the Technical Support Center (TSC) - Station Emergency Director (SED). The inspectors identified that the initial NARS Form was sent at 4:35 a.m.; however, the first follow up telephone call was not made until 6:11 a.m., a period of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 36 minutes. The ability to make follow-up notifications is an Inspection Follow-up item (IFl 50-461/98003-13).
Technical Support Center and Operations Support Center (OSC) Activation The CPS Emergency Plan, Section 3.1.2.2, required that upon activation of an Alert, key personnel shall report to the TSC so as to be fully operational within about one hour after the emergency activation. The licensee noted that upon emergency activation,1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 34 minutes elapsed prior to the TSC being fully operational. The inability to activate the TSC within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is a repeat deficiency from the October 1997 exercise.
Delays in activating the TSC were attributed to: (1) The global page was activated at 4:22 a.m., creating an eleven minute delay in initial notifications to the ERO. The inspectors noted that the delay in the global page was previously known to the licensee.
(2) Although the majority of key TSC responders arrived at around one hour from declaration of the Alert, the position of TAS remained vacant due to personnel assuming functions of greater importance per the line of succession. The individual responsible for the TAS position was delayed because he could not remember the telephone number to call for the ERO notification system, had to stop for gasoline, did not use the elevator, and processed through the PCM-2 contamination detection monitor outside the main control room instead of the Gamma 40 walk through contamination monitor in the OSC.
The ability of the staff to activate the TSC within one hour is considered an Inspection Follow-up Item (IFl 50-461/98003-14).
The inspectors noted that the OSC was staffed and activated at 5:26 a.m.,1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 15 minutes after the Alert declaration. The inspectors noted that a time requirement for activating the OSC was not specified in the Emergency Plan Implementing Procedure (EPIP). However, Emergency Plan Table 2-1, "Clinton Power Station Minimum Staffing,"
specified on shift,30 minute, and 60 minute staffing requirements for personnel. Through discussions with the licensee the inspectors determined that the licensee had not verified
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its ability to meet the minimum staffing requirements described in the emergency plan.
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l Upon further review, emergency planning personnel stated that Table 2-1 on shift staffing requirements were not met. Specifically, the 30 minute positions for inplant surveys, radiation protection personnel, and supervisor-technical or alternate were filled after more than 37 minutes. The 60 minute position for radiation protection personnel was filled after more than 75 minutes. The mechanical engineer position was not filled with a designated individual, however, personnel were present who could have filled the position. The 60 minute electrical maintenance position was filled by a qualified electrician who was not ERO qualified.
Emergency planning personnel stated that it was their expectation that each affected
department was responsible for ensuring minimum staffing requirements were met. The l
inspector questioned operations, maintenance, and radiation protection managers and determined that the affected departments could not explain how the minimum emergency plan requirements were met for on shift and 30 minute responders. In addition, the licensee could not identify how collateral assignments were performed. For example:
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a (1) emergency planning believed operations personnel could perform radiological self monitoring; however, radiation protection personnel stated that operations personnel were not qualified to perform self monitoring; and (2) emergency planning personnel believed that operations personnel could satisfy the requirement for mechanical and electrical maintenance activities, however, the licensee was unable to determine if operators possessed the requisite ski'Is and abilities to perform maintenance tasks.
As an interim measure, the licensee designated seven additional personnel to the on shift minimum staffing requirements from maintenance and radiation protection departments.
In addition, personnel with 30 minute and 60 minute response requirements were selected based on the proximity to the site and were briefed on the expediency of their response.
Emergency planning personnel stated that previous off hour notification drills did not account for the delay in activation of the autodialer. Approximately 10-12 minutes elapsed between emergency classification and notifications by the autodialer. Addition of the 10-12 minute autodialer delay to ERO member response times resulted in not being able to verify that 30 minute and 60 minute staffing goals could be met. Emergency planning personnel stated that an off hours exercise would be performed to verify the capability to meet minimum staffing requirements. The inability to ensure Emergency Plan Table 2-1 minimum staffing requirements were met is an Unresolved item (URI 50-461/98003-15).
Autodialer Operation and Familiarity The licensee determined that some ERO responders distracted on shift operations personnel by telephoning the main control room to see if the Alert was a drill or an actual event in lieu of immediately responding to the plant. Some ERO personnel did not know the correct number to call once their pager activated. Actions had been implemented prior to the Alert to change the pager display from a coded number to the actual phone number for responders. The licensee completed the actions to change from the coded number following the Alert.
The autodialer was programed to page personnelin a hierarchical order. Once a responder acknowledges the page, attempts to contact personnel for the same position are stopped. The licensee determined that during the Alert, the TAS responded prior to the SED and was assigned the responsibility of SED. Consequently, when the normal SED retumed the page, he was informed the position was already filled. The autodialer operation started a succession of events which ultimately resulted in untimely filling of the TAS position, a position requirea to activate the TSC. The licensee stated that changes would be made to the call out process to require an onsite response for both the normal and backup responders for each position. Changes to the autodialer operation are an inspection Follow-up item (IFl 50-461/98003-16).
SED Command and Control EPIP EC-12, " Emergency Teams," required that the SED authorize the formation and dispatch of emergency teams. The licensee determined that the SED was not always aware of operations teams formed and dispatched by the shift supervisor. The lack of oversight by the SED resulted in communication problems regarding restoration of plant
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equipment. For example, personnelin the TSC believed that three fill and vents of the RHR syatem occurred when there were only two. The main control room had completed a check list for an NSPS outage while the TSC/OSC was developing a team to perform the same checks. The oversight of field teams by the TSC/OSC is a repeat deficiency from the October 1997 exercise. The ability of the SED to authorize and control the formation and dispatch of field teams is considered an Unresolved item (URI 50461/98003-17).
The TSC-SED assumed the lead role but did not direct or coordinate the response activities of the facility. Essentially, the shift supervisor did not relinquish command authority over the ERO and continued to establish the priorities for the station throughout the duration of the Alert. The transition of authority between the main control room and the SED is an inspection Follow-up item (IFl 50461/98003-18).
Use of Emergency Response Organization Badges EPIP EC-09, " Security During Emergencies," Section 4.5, "ERO Personnel Identification,"
specified that members of the ERO were issued emergency access badges to allow entry into the protected area and emergency facilities. The licensee determined that several personnel did not have or were unaware of the need to have an ERO badge. Not having an ERO badge created delays in gaining access to the protected area in that security personnel were required to verify ERO members against a non-alphabetical listing of ERO personnel. An alphabetical list was available, however, security personnel were unable to locate the list during the event. Not possessing an ERO badge could delay the response to the facility if state and local authorities established road blocks to minimize access to the plant. Ensuring ERO personnel have been issued the appropriate identification badge and the ability to use the ERO badge to gain unimpeded access to the facility is an Unresolved item (URI 50461/98003-19).
Field Samples Brought into the EOF EPIP RA 17 " Radiological Control of the EOF," Section 4.2.4, " Field Team Access,"
required that returning field teams deliver field samples to the secondary door (north of the EOF main entrance) leading to the environmental sample analysis laboratory. The licensee determined that field team members initially brought field samples to the secondary door of the EOF, however, since no one was present to answer the door, the field team members brought the field samples into the EOF through the normal EOF entrance. The secondary door is provided to prevent contaminating the EOF. The ability to control field samples being returned to the EOF is an Inspection Follow-up item q
(IFl 50461/98003-20).
Communications The licensee noted that three-part communications were not used by all ERO personnel and that reminders made during the Alert improved communications for short durations.
The licensee noted that communications between the main control room and the TSC were difficult in that a dedicated communicator was not established in the control room, personnel would not answer the phone in the control room as activities increased.
Attempts to perform face to face communications with personnel dispatched from the i
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TSC were occasionally disapproved. Priorities were not clearly communicated between the TSC and the main control room. The ability of the TSC to effectively communicate with the main control room is an inspection Follow-up item (IFl 50-461/98003-21).
The licensee noted that site wide announcements were infrequently made and did not include information regarding the status of the plant. For example, security personnel informed ERO personnel that a loss of coolant accident had occurred instead of a loss of shutdown cooling and some plant personnel were notified that the Alert had been downgraded to a Notification of Unusual Event. The ability to disseminate accurate information to plant personnel is a repeat deficiency from the October 1997 exercise and is an inspection Follow-up Item (IFl 50-461/98003-22).
Procedure Usage in the TSC The inspectors noted that TSC personnel frequently referenced emergency operating procedures.
Comparison to October 1997 Exercise Improvements noted in the main control room included the ability to restrict access to the main control room, oversight of plant operators, and restoration of plant equipment.
Improvements noted in the TSC included use of EOPs and status board ;nformation. The critique performed by the ERO provided a critical assessment of licensoe performance during the Alert.
Three TSC deficiencies identified during the October 1997 exercise were repeated.
These deficiencies included late activation of the TSC, poor status updates to plant personnel, and a lack of control by the SED and the OSC of field teams dispatched by the main control room.
c.
Conclusions The shift supervisor maintained an oversight role of activities in the control room and prompted actions when appropriate. The LASS controlled the activities of ROs and NLOs. The shift supervisor used conservative decision making to activate the ERO in order to obtain additional resources to restore shutdown cooling.
The inspectors noted that the shift supervisor limited access to the main control room by assigning an individual the responsibility to prevent entry by non essential personnel.
j This action significantly reduced the number of distractions in the main control room.
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Operations personnel demonstrated good use of emergency, off normal, and system operating procedures in the main control room.
The licensee performed a critical assessment of the ERO performance during the Alert.
The assessment was a significant improvement from the assessment of the October 1997 exercise. Deficiencies noted by the licensee included; the inability of a non-licensed operator to perform initial notifications, the use of the shift technical advisor to perform initial notifications, performance of follow-up notifications, untimely transmission of data to the NRC, State, and EOF, late activation of the TSC, autodialer operation, control of field teams, communications, use of identification badges, and control of field samples.
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The inspectors determined that minimum emergency plan staffing for on shift,30 minute, and 60 minute response were not met by the licensee. Consequently, the licensee added seven personnel to the on shift organization and dedicated individuals living within close proximity to the station emergency response organization duties.
S1 Conduct of Security and Safeguards Activities S1.1 Vehicle Search Observations (71750)
On February 17,1998, the inspectors observed the search of a vehicle entering the protected area. The security officers searched all areas of the vehicle and used the appropriate visual aids when needed. No deficiencies were identified.
F1 Control of Fire Protection Activities F1.1 Fire Watch Tour of EDG Spaces a.
Inspection Scope (71750)
The inspectors reviewed compensatory measures being implemented for fire impairments effecting the Division I,11, and lll EDG rooms.
b.
Observations and Findinas On February 12,1998, the inspectors observed a fire watch open the Division II EDG room door and scan the bar codes associated with impairments for the space. The fire watch did not perform a tour of the space to check for combustible materials or the presence of a fire.
I Licensee management initially informed the inspectors that the actions taken by the fire watch were appropriate in that the individual visually checked the impairment (inuperable
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carbon dioxide suppression system) as required by training provided to fire watch i
personnel. The inspectors questioned the licensee to determine why a tour of the effected space was not performed to verify the absence of a fire or combustible materials as a preventive measure since the automatic suppression system was inoperable. On February 19, the licensee acknowledged that the tour of the space should have been performed as a preventive measure in accordance with plant procedures, that the bar code had been relocated to the far end of the EDG room, and that fire watch personnel had been briefed on the need to tour spaces with fire impairments.
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Procedure 1893.16, " Fire watch," Section 8.4, required, in part, that the individual assigned to fire watch be responsible for being cognizant of fire hazards in the area. The inspectors determined that the failure to perform a tour of the Division II EDG room in order to be cognizant of potential fire hazards in the area a violation of TS 5.4.1.a.
However, because significant NRC enforcement action was taken for a programmatic breakdown in procedure adherence and the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy),
NUREG-1600 were met, a Notice of Violation is not being issued (IFl 50-461/98003-01d).
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Conclusions Fire watch personnel failed to be cognizant of fire hazards in the Division ll EDG room.
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 March 4,1998. 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.
X3 Management Meeting Summary On February 5,1998, NRC members of the Clinton Restart Panel met with lilinois Power management to discuss the development of the Plan for Excellence and current conduct of operations concerns.
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PERSONS CONTACTED Licensee -
G. Baker, Manager-Quality Assurance
. W.Carsky, Director - Design Engineering V. Cwietniewicz, Manager - Maintenance J. Goldman, Manager - Work Control G. Hunger, Plant Manager W. MacFarland IV-Chief Nuclear Officer W. Maguire, Director - Operations W. Romberg, Manager - Nuclear Station Engineering Department J. Sipek, Director - Licensing D. Smith, Director-Security and Emergency Response M. Tacelosky, Supervisor - Operations Services S. Lakebrink, Group Leader - Design Engineering
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INSPECTION PROCEDURES USED IP 37551: Engineering Observations IP 61726: Surveillance Observations IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support IP 92901: Followup - Operations IP 92902: Followup - Engineering IP 92903: Followup - Maintenance IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Opened'
50-461/98003-01a NCV Enforcement Discretion: Corrective actions for improper manipulation of main control room computer screen.
50-461/98003-02a NCV Enforcement Discretion: Failure to implement corrective actions to prevent recurrence of an unmonitored increase in main control room deficiencies and operations workarounds.
50-461/98003-01b NCV Enforcement Discretion: Failure to restore control room breathing air system air header pressure in a timely manner.
50-461/98003-03a NCV Enforcement Discretion: Failure to ensure design requirements for minimum breathing air system pressure.
50-461/98003-04 NCV Enforcement Discretion: Failure to operate traveling screens during cold wea;her to prevent ice blockage.
50-461/98003-05 URI Review of operations ability to meet manning requirements specified in emergency plan and lack of training to support remote shutdown operations.
50-461/98003-06 NCV Enforcement Discretion: Failure to implement timely corrective actions to prevent both EDGs from being inoperable.
50-461/D8003-01c NCV Enforcement Discretion: Failure to irnplement provisions of the maintenance troubleshooting procedure.
50-461/98003-03b,c NCV Enforcement Discretion: Failure to ensure design basis information was translated into specifications for EDG loading, service life of components, and for electrical isolation.
50-461/98003-07 NCV Enforcement Discretion: Failure to ensure RTD testing was included as part of test control program.
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,s 50-461/98003-08 NCV Enforcement Discretion: Failure to perform an adequate 50.59 evaluation when changed testing methodology for the diesel ventilation system.
50-461/98003-09 NCV Improper operating limit for Minimum Critical Power Ratio.
50-461/98003-10 URI improper use of the shift technical advisor to perform initial off site notifications.
50-461/98003-11 URI Inability to transmit updated information within one hour using the emergency response data system.
50-461/98003-12 IFl Reliability of the ND-6685 computer.
50-461/98003-13 IFl Ability to complete follow-up notifications to the State.
50-461/98003-14 IFl Ability to demonstrate activation of the technical support center within one hour.
50-461/98003-15-URI Inability to maintain minimum emergency plan staffing requirements.
50-461/98003-1S IFl Ability to activate and respond to the autodialer system.
50-461/98003-17 URI Ability of the SED to authorize and control formation and dispatch of field teams.
50-461/98003-18 IFl Transition of authority between main control room and SED.
50-461/98003-19 URI Ensuring ERO has been issued ERO badges and review the ability to gain access to facility during events.
50-461/98003-20 IFl Ability to control field samples being returned to the EOF.
50-461/98003-21 IFl Ability of TSC to effectively communicate with the main control room.
50-461/98003-22 IFl Ability to disseminate accurate information to plant personnel.
50-461/98003-01d IFl Enforcement Discretion: Failure to perform adequate fire watch tour of EDG rooms.
Closed 50-461/96006-02 IFl Implementation of corrective actions in response to having both trains of control room ventilation inoperable.
50-461/97-002 LER Failure to complete Technical Specification 3.8.2 limiting condition for operation required action B.4.
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50-461/96006-03 VIO Inoperable leak detection instrumentation due to poorjob preparation.-
50-461/97-001 LER Failure to nuclear supplier to analyze turbine pressure regulator down scale failure event.-
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50-461/P7-022 LER Design of Diesel Generator Ventilation Subsystems Outside Design
= Basis as a Result of Failure to include Minimum and Maximum Outside Air Temperature Extremes Due to Design Error.
50-461/98003-09 NCV Improper operating limit for Minimum Critical Power Ratio.
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LIST OF ACRONYMS CAL Confirmatory Action Letter CCF Comment Control Form CR Condition Report ECN Engineering Change Notice EDG Emergency Diesel Generator EOF Emergency Operations Facility EPIP Emergency Plan Implementing Procedure ERDS Emergency Response Data System ERO Emergency Response Organization EWR Engineering Work Request LAG Independent Analysis Group IDNS lilinois Department of Nuclear Safety ITR independent Technical Review KW Kilowatt LASS Line Assistant Shift Supervisor LER Licensee Event Report MCPR Minimum Critical Power Ratio MCR Main Control Room MWPH Makeup Water Pump House MWR Maintenance Work Request NARS Nuclear Accident Reporting System NLO Non-licensed Operator NSPS Nuclear System Protection System OSC Operations Support Center PDR Procedure Deviation for Revision PM Preventive Maintenance RA Breathing Air System RHR Residual Heat Removal RO Reactor Operator RT Reactor Water Cleanup RTD Resistance Temperature Device SED Station Emergency Director STA Shift Technical Advisor TAS Technical Assessment Supervisor TPD Temporary Procedure for Deviation TS Technical Specifications TSC Technical Support Center USAR Updated Safety Analysis Report VD Diesel Ventilation System WX Solid Radwaste Reprocessing
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