IR 05000029/1986008
| ML20215M689 | |
| Person / Time | |
|---|---|
| Site: | Yankee Rowe |
| Issue date: | 10/24/1986 |
| From: | Elsasser T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20215M682 | List: |
| References | |
| 50-029-86-08, 50-29-86-8, NUDOCS 8611030165 | |
| Download: ML20215M689 (33) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
Report N /86-08 Docket N Licensee N DPR-3 Licensee: Yankee Atomic Electric Company 1671 Worcester Road Framingham, Massachusetts 01701 Facility Name: Yankee Nuclear Power Station Inspection at: Rowe, Massachusetts
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Inspection Conducted: June 10 - October 6, 1986 Inspectors: H. Eichenholz, Senior Resident Inspector D. Haverkamp, rojec Engineer S. Pindale si t Inspector - Haddam Neck Approved By: *
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- ~ /0hM T. Elsasser , Reactor Projects Section 3C Date Summary: Inspection on June 10 - October 6, 1986 (Report No. 50-29/86-08)
Areas Inspected: Routine onsite regular and backshift inspection by resident and region-based inspectors (200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />). Areas inspected included licensee action on previous findings, operational safety verification, radiological controls, events requiring telephone notification to the NRC, plant events, maintenance observations, surveillance observations, bimonthly safety system walkdown, onsite review committee activities, licensee response to IE Bulletins, plant procedures program, Emergency Planning Drill, licensee response to selected safety issues (TI 2515/77), and fit-ness for duty concern Results: One violation was found involving failure to maintain and verify closed the main coolant loop bypass valve in at least one of the loops that is in operation i (Section 3). One inadequacy involvirq failure to provide a timely ENS notification
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asrequiredby10CFR50.73wasclaspifiedasalicenseeidentifiedviolation(Sec-tion 6). Ten areas needing increased; licensee attention were (1) performance of 10'CFR 50.59 evaluations (Section 4); (2) control of protected area portals and isslation 2Lnes (Section 4), (3) tra ining and implementing procedural controls for I the use of large calibratian sources (Section 5), (4) timely resolution of technical
- issues by the Yankee Projects Department (Section 5), (5) describing root cause and corrective actions in LERs (Section 5), (6) Special Order used in lieu of pro-cedures (Section 7), (7) lifted lead / jumper procedure implementation (Section 8),
(8) response to 10 CFR 21 notification (Section 8), (9) generation, implementation and maintenance of plant procedures to control routine activities, including TS
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8611030165 861024 PDR ADOCK 05000029 G PDR
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surveillance requirements (Sections 4, 7, 9, 10, 12, and 13), and (10) minimal training department involvement / assessment of fire protection training (Section a 7). Prompt aggressive actions were taken by the plant organization in response
- to the identification that electrical equipment could become overloaded during certain plant evolutions and also in response to a potential loss of shutdown cooling event (Section 7). Fire protection, prevention, and housekeeping practices (Section 4), implementation of ALARA (Section 5), planning and controlling activi-ties in an extended maintenance outage (Section 7), and a conservative approach to plant safety and operations (Section 7) were considered notable strengths. A positive trend was observed in the maintenance of control room logs and records (Section 4).
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DETAILS Persons Contacted Yankee Nuclear Power Station B. Drawbridge, Assistant Plant Superintendent T. Henderson, Technical Director .
N. St. Laurent, Plant Superintendent The inspector also interviewed other licensee employees during the inspection, including members of the Operations, Radiation Protection, Chemistry, Instru-ment and Control, Maintenance, Reactor Engineering, Security, Training, Tech-nical Services, and General Office Staff . Summary of Facility Activities At the completion of the last resident inspection period on June 9, 1986, the plant was at 100% of rated power. The plant maintained that power level until June 13, 1986 when an unplanned load reduction to 75% of rated power was in-
-itiated by the licensee in response to a leak in the packing gland of the N boiler feed pump. The plant was again at 100% of rated power on June 15, 1986. Subsequently, on June 18, 1986, a plant shutdown was initiated due to the discovery of a leaking weld in a coupling on the No. 2 steam generator's blowdown line. During this shutdown, the licensee determined that an abnor-mally low No. 1 main coolant pump flow indication was attributed to a failure of the valve stem of the loop's hot leg isolation valve (MC-MOV-325).
During the plant shutdown, the licensee informed the NRC that four valves in the reactor coolant vent and energency feedwater systems had incorrect over-load trip coils installed in their respective power supply circuit breaker This occurrence is the subject of a special NRC Inspection, 50-29/86-09. Also during this plant shutdown, a valving error by a plant auxiliary operator resulted in the potential for both a loss of shutdown cooling and severe damage of the main coolant pump internals (see Sections 6 and 7).
A plant startup was initiated on July 1,1986 and the plant operated at 100%
of rated power from July 5, 1986 until a planned load reduction to 50% of rated power occurred on September 20, 1986 to allow turbine throttle valve and main steam non return valve testing, conduct condenser tube leak checks,
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and perform required maintenance on boiler feedwater pumps. The plant was at 100% of rated power on September 21, 1986, and was maintained essentially at this power level until October 4,198 On this date a low control air pressure condition occurred that subsequently resulted in a plant scram on low steam generator levels. During the plant startup later the same day, an operator error resulted in the inadvertent closure of the main steam non-return valves and a reactor scram occurred. The plant startup was again in-itiated on October 5, 1986, with the plant at 75% of rated power at the end
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of the inspection period on October 6,198 . - -_
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4 Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (50-29/86-04-01): Revise chemistry manager and radi-ation protection manager position descriptions by August, 1986. The licensee approved job descriptions for the Plant Chemistry Manager and Radiation Pro-tection Manager on July 25, 1986. Duties and responsibilities were defined clearly and were comprehensive, including the responsibilities for implementing the Process Control Program, Offsite Dose Calculation Manual and Radiological Environmental Technical Specifications. This item is considered close (Closed) Unresolved Item (50-29/86-05-01): Review Licensee's Safety Analysis For Having All Main Coolant Loop (MCL) Bypass Valves Open In Mode 3. This item reflected a failure of the plant operators to conduct operations in accordance with TS 3.4.1.1.2 and 4.4.1.1.2.3 on June 2, 1986. At the time of this occur-rence, the NRC was unable to ascertain if the operating conditions negated any safety analysis assumptions, or resulted in any operational safety con-cerns. Inmediate inspector concerns at the time involved the potential for degradation of the decay heat removal function during natural circulation with the MCL bypass valves open. The inspector requested that the licensee perform the necessary evaluations of this incident to ascertain the safety signifi-cance of the even The licensee was responsive to the NRC request, as evidenced by the completion of the evaluations conducted by the Transient Analysis and LOCA Groups of the Yankee Nuclear Services Division (YNSD) on June 27, 1986. The evaluations, identified in Memorandum TAG 86-171, were subsequently transmitted to the plant's technical director by the YNSD Yankee project manager on July 8, 198 The inspector reviewed the memorandum and noted the following: The Transient Analysis Group's review of safety analysis assumptions and calculations on the effects of MCL bypass during natural circulation in-dicated that no safety analysis assumptions were violated and there were no actual safety concerns raised as a result of the operating conditions on June 2, 1986. The calculations performed provide a licensing basis for a TS change to remove the bypass valve position requirements in Mode 3. The events analyzed for were 1) boron dilution, 2) main steam line break, and 3) complete loss of feedwate As a result of the licensee's review of their LOCA analyses, which is based upon operation at a 103% power level, the operating conditions that occurred on June 2, 1986 did not violate any LOCA analysis assumption Technical Specification 3.4.1.1.2 stipulates that when in Mode 3 all MCLs shall be operable, with all loop isolation valves open and at least one main coolant loop in operation. Technical Specification Surveillance 4.4.1.1.2.3.b requires that the steam generators associated with the main coolant loops required to be in operation have their respective cold and hot leg stop valves fully open with the bypass valves verified closed once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In addition, Technical Specification 6.8.1. specifies that written procedures be established and implemented that meet or ex-
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ceed the requirements and recommendation of Appendix A or Regulatory Guide 1.33, Revision.2. Regulatory Guide 1.33 calls for implemented pro-cedures for TS surveillance test The licensee's actions: 1) to open the bypass valves in all 4 MCLs from 4:25 a.m. to 8:47 a.m. on June 2, 1986 while the plant was in Mode 3, which results in not having at least one MCL in operation as required by Technical Specification 3.4.1.1.2.b; 2) to not perform at least once, while the plant was in Mode 3 between 8:34 p.m. on June 1, 1986 and 9:36 a.m. on June 3, 1986, the required surveillance of Technical Speci-fication 4.4.1.1.2.3.b; and 3) to not establish a procedure to conduct the aforementioned surveillance, are considered to collectively consti-tute a violation (50-29/86-08-01); unresolved item 86-05-01 is considered close . Operational Safety Verification Daily Inspection During routine facility tours, the inspector checked the following items:
shift manning, access control, adherence to procedures and limiting con-ditions for operation (LCO), instrumentation, recorder traces, protective systems, control rod positions, containment temperature and pressure, control room annunciators, radiation monitors, radiation monitoring, emergency power source operability, control room and shift supervisor log, tagout log, and operating orders. No inadequacies were identified except as noted belo Plant procedure AP-0017, Rev.10, Switching and Tagging Of Plant Equipment, requires at 6 month intervals that all active tags will be checked to ensure that the tags are properly hung, are legible and are properly recorded. The inspector confirmed that the licensee had completed the required review on June 10, 1986. No deficiencies were identified in licensee performance on this ite Throughout the inspection period, the inspector noted the continued excellent level of performance of the licensee in maintaining the control room annunciators in as close to a " black-board" status as possibl In the previous inspection report, 50-29/86-05 Section 4.a, the in-spector noted that although control room personnel maintenance of required logs and records was improving, a consistent high level of performance has not been achieved. This has been especially true for recognition by control room personnel that applicable TS action statements are to be recorded in the appropriate logs. During this inspection interval, the inspector noted a significant number of entries into TS action statements by the licensee. Almost without
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exception, the control room records reflected the observed activit These observations demonstrate that a consistent high level of per-formance is achievable by control room personnel in this are In response to excessive valve stem leak off temperatures, the con-trol room operators during full power operations on June 9, 1986 opened and backseated the No. 1 main coolant loop bypass valve MC-MOV-501. Following a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period of operating in this manner, and with no reduction in the temperature, the valve was close Similarly on June 10, 1986 the bypass valve in loop No. 4, MC-MOV-504, was opened to it's back seat position. This resulted in an observed temperature reduction. Licensee plans at the time were to run in this configuration for the remainder of the cycle that ends in May, 198 On June 10, 1986, the inspector reviewed the licensee's actions due to the following considerations: 1) FSAR Section 201 indicates that the intended use of the bypass line is to permit warming a cool isolated loop, via recirculation, prior to returning a loop to operation, 2) plant procedure OP-2130, Rev. 7, Startup And Cut-In Of An Isolated Loop leaves the bypass valves closed and no other licensee procedure addresses the use of these valves during normal operation, and 3) Technical Specification 3.2.4 requires maintenance of a minimum main coolant total flow rate of 38.3E06 lbm/hr. The inspector held a discussion with the reactor engineering manager about this operating configuration, requested that he provide docu-mentation that demonstrates that the plant is being operated within the envelope of applicable analyses, and provide verification that the required core coolant flow rate is being maintaine The reactor engineering manager provided the inspector with Memoran-dum NED 81-756, prepared on December 11, 1981 by the YNSD nuclear engineering department, which evaluates the loop bypass flow effect The memorandum demonstrates that no TSs applicable to core thermal design limits are violated when one or two loop bypass valves are opened at full power conditions. Furthermore, it demonstrates that neither the consequences of LOCA events, nor the thermal design margins for non-LOCA transients are affected in significantly ad-verse ways, when operating in this manner. However, the inspector noted that the memorandum's recommendation to consider modifying the TSs to better reflect the basis for the minimum flowrate re-quirement when operation with opened bypass valve is necessary, did not result in a change to the TS Additionally, the reactor engineering manager provided main coolant flow rate calculations for inspector review, which utilized proce-dure OP-4715, Rev. 5, Main Coolant Flow Rate Determination, for the conditions of 1) all bypass valves closed, 2) loop 1 bypass valve open and 3) loop 4 bypass valve open. The inspector noted that this procedure requires, as a prerequisite, to have all loop bypass
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valves closed. The reactor engineering manager incorporated the results of the calculations in a June 13, 1986 memorandum that dis-cussed the issue and demonstrated compliance with the Technical Specification 3.2.4 minimum flow requirement. This memorandum was subsequently contained in Operations Department Special Order 86-66 that provided justification for the operating configuration to the plant operators. Additionally, the inspector noted that the licen-see's Safety Analysis Assumptions document did indicate that the loop bypass valves can be opened as long as the core coolant flow rate can be verified to be greater than or equal to the assumed flow rate of 38.3E06 lbm/hr. This document, however, did not include NED 81-756 memorandum's limitations that analyses at the present time can only support a maximum of two bypass valves being open at the same time while in Mode Based upon the above information the inspector requested that the licensee take the following action: 1) develop a Safety Evaluation for the operating configuration discussed above that will be re-viewed and reported in accordance with 10 CFR 50.59 and TSs require-ments, 2) address operating restraints and appropriate confirmatory measurement requirements for normal plant operation with the main coolant loop bypass valve (s) open in a plant procedure (s), and 3) consider revising the FSAR to reflect analyses and operating in-formation pertinent to operation of the main coolant loops with the bypass valve (s) ope The licensee's representatives indicated that the requests would be implemented. Notwithstanding this action, the inspector's review of the licensee's activities in this area demonstrates the need for continued licensee management attention to insure that the require-ments of 10 CFR 50.59 are implemented and that written procedures are established to control plant operating conditions. The inspector had no further questions on this ite System Alignment Inspection Operating confirmation was made of selected piping system trains. Access-ible valve positions and status were examined. Power supply and breaker alignments were checked. Visual inspections of major components were performed. Operability of instruments essential to system performance was assessed. The following systems were checked:
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Steam driven emergency feedwater pump unit standby verified during tours of the Auxiliary Boiler Room
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Charging system verified during control room board status review
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Non-return valves (NRV) verified during tours of the NRV platform and during a control room equipment cabinet review l
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Motor driven emergency feedwater pump standby status verified during
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tours of the primary auxiliary building and during a control room board status review
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Low pressure accumulator system tours of the control room and safety injection building No unacceptable conditions were observe Biweekly and Other Inspections (1) During plant tours, the inspector observed shift turnovers, compared boric acid tank samples and tank levels to Technical Specifications requirements, and reviewed the use of radiation work permits and radiation protection procedures. Area radiation and air monitor use and operational status were reviewed. Verification of tagouts indi-cated the action was properly conducted. There were no inspector identified deficiencies in this are (2) Observations of Physical Security Selected aspects of plant security were reviewed during regular and backshift hours to verify that controls were in accordance with the security plan and approved procedures. This review included the following security measures: guard staffing; random observations of the alarm stations; verification of physical barrier integrity in the protected and vital areas; verification that isolation zones were maintained; and implementation of access controls, including identification, authorization, badging, escorting, personnel and vehicle searches and compensatory measures when require From July 28 - August 1, 1986, the inspector participated in a regulatory effectiveness review team inspection of the licensee's Security Program. Inspector observatinns will be contained in the team report that will be issued at a later dat The inspector identified no violations in this area. However, the following deficiencies or concerns were identified:
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On September 3, 1986 the inspector toured the central alarm station (CAS) and identified to the CAS operator an equipment deficiency that would preclude his effective surveillance of a portion of the protected area boundary. The nature of the equipment deficiency could have just occurred and the inspec-tor's identification of the condition is not a statement of inattentiveness by the CAS Operator. Immediate compensatory measures were implemented and documented. The inspector veri-fied that the licensee's actions were consistent with the security plan and implementing procedures. A maintenance re-quest was issued to correct the equipment deficiency, which
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were verified to be properly resolved on September 4, 198 Although not routinely evident, the licensee's response of providing rapid and effective equipment repairs to security equipment was noted by the inspector in this case. Continued management attention is still warranted to insure that security equipment corrective and preventive maintenance activities receive appropriate priority by the various plant operating department While reviewing the status of the protected area barrier (PAB)
during a plant tour on September 5, 1985, the inspector re-viewed licensee practices involving the protected area portal The inspector identified a concern pertaining to one of the practices, obtained concurrence from the NRC: Region I safe-guards section chief that the concerns were valid and warranted additional review, and requested that the licensee's security supervisor review the inspector's concern for remedial actio The security supervisor acknowledged the inspector's comments and concerns, and indicated that they would be reviewed in a timely manner by himself and the assistant plant superintenden The inspector was notified on September 8, 1986 that new in-structions have been transmitted to the security organization for immediate implementation that fully resolved the inspector's concerns. The inspector had no further questions of the licen-see on this ite As a result of performing a PAB inspection on September 11, 1986, the inspector noted excessive vegetation growth at various locations on both sides of the isolation zones of the protected area. The isolation zone is to be free cf visual obstructions. Inspections of the isolation zone are conducted by security personnel as a requirement of procedure DP-0429, Rev. 13, Foot Patrol Duties and Responsibilitie The inspector reviewed the results of the DP-0429 inspections conducted on August 1 and 29, 1986, noted that the growth was listed as a discrepancy, and determined that the licensee's contractor hired to correct the condition was scheduled to start and complete the work no later than September 21, 198 Inspector concerns pertaining to the existence of unsatisfac-tory conditions within the isolation zone, and the need for immediate licensee corrective action, were discussed with the security supervisor and the assistant plant superintendent on September 11, 198 Discussions were held with the licensee on September 12, 1986 about the unacceptable conditions, and included the involvement of the NRC: Region I assigned security specialist inspector for the facility. The licensee committed to removing some of the
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growth in one particular area using licensee personnel on ,
September 12, 1986, and indicated that accelerating the arrival of their contractor would be investigated. The contractor ar-rived on-site on September 15, 1986 and proceeded to correct the discrepant condition The inspector had noted in Inspection Report 50-29/85-24 con-cerns pertaining to the lack of effectiveness of the licensee in maintaining the proper integrity of the Protected Area's isolation zone. The current observed conditions appear to be another indication of ineffective licensee management overview in the security area. The integrity of the isolation zone will be reviewed by the inspector during routine facility inspec-tion (3) Fire Protection and Housekeeping
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No inadequacies were noted regarding licensee housekeeping practices. A strong commitment to proper housekeeping condi-i tions and practices by the plant staff is routinely observed by the inspecto Throughout the inspection period, the licensee has experienced
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the loss of fire protection barriers, detection systems, and firefighting features of the plant. The losses of function re-sulted from both preventive maintenance and unexpected equip-ment inoperabilities. In all cases, the inspector has observed a rapid deployment of compensatory measures by the operating staff. The licensee's performance in the area of fire protec-tion and prevention continues to be viewed by the inspector as a licensee strengt . Radiological Controls
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Radiological controls were observed on a routine basis during the reporting period. Standard industry radiological work practices and conformance to radiological control procedures and 10 CFR Part 20 requirements were observe Independent surveys of radiological boundaries and random surveys of non-radiological areas throughout the facility were taken by the inspector.
During the inspection period, the licensee exhibited strong performance in the ALARA area. The inspector's ALARA observations occurred during the plant outage that started on June 18, 1986 to repair the leak on the No. 3 steam generator's blowdown line. As a result of 1-3 Rem /hr. general area dose rates
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in the main coolant loop, the plant managers determined that plant shutdown would be required for repairs. Significant work activities involving the
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potential for high exposure to workers included the repair of the separated stem and disc on the loop 1 hot leg isolation valve, MC-MOV-325, and a bonnet leak on the charging line valve in loop 4, CH-MOV-524. The inspector observed ALARA control techniques that were implemented for time saving, dose rate i
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reduction, and contamination control. According to the licensee's ALARA engi-neer, the preplanning and implementation efforts resulted in an estimated 50%
reduction in exposure associated with the repairs to valve MC-M0V-325. The licensee has also been effectively utilizing their new Health Physics Infor-mation System to perform ALARA tracking. In addition to the field observations, the inspector reviewed the licensee's ALARA post job review report on the repairs to valve MC-MOV-325. This report reflects a strong commitment and effective implementation of the ALARA philosophy. The inspector's review in this area resulted in a conclusion that both plant and department managers support the ALARA Progra With the exception of the following item, no deficiencies were identified in this area:
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The inspector reviewed licensee activities involving the control of calibration sources on September 6, 1986. On this date the licensee was implementing procedure DP-8404, Rev. 7, Dosimetry Service Quality Control Program. The implementation of this procedure causes 6 control dosimeters to receive an approximately 300mR exposure utilizing a 1.2Ci Cs-137 source in a Shepherd Model 28-6A calibrator. The exposure time using the source was to be approximately.1 hou The licensee's control of calibration sources is governed by procedure DP-8108, Rev. O, Control or Calibration Sources. The procedure was established to provide guidelines to the radiation protection (RP) de-partment technicians to define, post, barricade, and control access to radiation fields generated by the handling of the calibration source A prerequisite of the procedure is that all personnel performing activi-ties covered by this procedure will be trained in accordance with proce-dure AP 8001, Radiation Protection Department Organization and Trainin This is, however, inadequate in tnat there is no direct reference to re-quiring that an RP Technician will receive training in the implementation of procedure DP-8108. Additionally, DP-8108 specifies that an up-to-date Calibration Source Dose Topology form (DPF-8108.1) exists for the exact source and geometry to be use The inspector determined that the RP technician performing the activities in question did not ascertain that an up-to-date form DPF-8108.1 existe In fact, no form had been generated by the RP Department ever since the new source and calibrator were placed in service in June, 1986. However, the inspector verified by performing independent measurements that the postings in use were correct for the radiological conditions. The RP technician did not receive training in the use of the DP-8108 procedur The required form DPF-8108.1 was immediately completed by the RP techni-cian on September 6, 1985 following identification of the omission by the inspecto In a previous NRC inspection completed in November, 1984 (50-29/84-20)
the inspector raised concerns pertaining to the licensee's use of large calibration sources. The development and implementation of procedure
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DP-8108 was the licensee's appropriate response to those concerns. It appears that the RP department was not successful in providing adequate training to their technicians to insure procedural requirements of pro-cedure DP-8108 were being implemented. The inspector's observations also demonstrate that there is a lack of effective first line supervisory overview occurring in this area. The inspector held a discussion with-the RP Manager on September 8, 1986, who acknowledged the inspector's comment's and concerns. As a result of this meeting the inspector learned that there had been other corrective actions implemented by the licensee to address mutual concerns relative to using calibration sources. Not-withstanding these factors, he indicated that procedure DP-8108 should have been implemented when the calibrator was put in service and aggres-sive corrective actions will be instituted as a result of the inspection findings. The corrective action included the issuance of an RP Department Special Order that required a review by all RP technicians of procedure DP-810 The inspector's findings in this area indicates that senior plant man-agement's high level of attention to the performance of the RP Department continues to be warrante . Events Requiring Telephone Notification to the NRC The circumstances surrounding the following events, which required NRC noti-fication via the dedicated ENS-line, were reviewed. A summary of the inspec-tor's review findings follows or is documented elsewhere as noted below:
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On June 18,1986 at 1:25 p.m. , the licensee made an informational noti-fication to the NRC that at 12:00 noon that a controlled plant shutdown from a full power condition was initiated to perform repairs to a leaking weld on a coupling in the 2" blowdown lin.e on the No. 3 steam generato This event is discussed in Section 7 of this repor At 4:35 p.m. on June 18, 1986, licensee notified the NRC via the ENS line i
in accordance with 50.72 (b)(2)(iii) that a recent plant electrical sys-tem evaluation identified overloading concerns associated certain elec-
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trical equipment. This event is discussed in Section 7 of this report.
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At 4:50 p.m. on June 23, 1986, with the plant in Mode 5, the NRC was notified in accordance with 50.72 (b)(2)(i), that a valve stem failure was identified on the No. I loop hot leg isolation valve (MC-MOV-325).
This event is discussed in Section 7 of this repor At 5:00 p.m. on June 26, 1986 with the plant in Mode 5, the NRC was noti-fied in accordance with 50.72 (b)(2)(iii)(D) that four valves in the reactor coolant vent and emergency feedwater systems had incorrect over-load trip coils installed in their respective power supply circuit breakers. This event was the subject of a special NRC Inspection, 50-29/86-0 . _ - _ . - . _ _ _ _ . - .- - . --
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On July 3, 1986, at 10:40 a.m., with the plant in Mode 5, the licensee notified the NRC in accordance with 50.72(b)(2)(iii)(B) that a potential loss of shutdown cooling event had occurred on June 27, 1986 as a result of a valve misalignment. This event is discussed in Section 7, of this report. However, the event was not reported in a timely manner as re-quired by 10 CFR 50.72. A licensee representative informed the inspector that since the event did not disable the shutdown cooling system, nor would it have for a long time even if no compensating actions were taken, the plant managers initially determined that the event was not reportabl A subsequent review of NUREG 1022, Supplement 1, raised same doubts in the licensee's view' as to the correctness of their initial decision. The inspector has noted over an extensive period of time that the plant man-agement's reporting philosophy is very conservative, and has been recog-nized by the NRC as a licensee strength. Because this appears to be an isolated incident and the criteria of 10 CFR 2, Appendix C, have been met, no Notice of Violation will be issue Other than the licensee identified violation above, the inspector found no further deficiencies in this are On October 4, 1986 at 10:23 a.m., with the plant in Mode 1, the licensee notified the NRC in accordance with 50.72(b)(2)(ii) of an automatic reactor scram that occurred at 9:38 a.m. as a result of low steam genera-tor level This event is discussed in Section 7 of this repor On October 5,1986 at 12:10 a.m. , with the plant in Mode 2, the licensee notified the NRC in accordance with 50.72(b)(2)(ii) of an automatic reactor scram that occurred at 11:15 p.m. on October 4,1986, due to an operator error that resulted in the closure of the main steam non-return valve This event is discussed in Section 7 of this repor . Plant Events Plant Shutdown For Repair of Steam Generator (S/G) Blowdown Line Following iricreasing indications of leakage into the vapor container (VC)
drain tank, the licensee initiated a containment inspection at 10:38 on June 18, 1986. The inspection located the sou.rce of the leakage into the containment to be from the No. 3 S/G 2" blowdown line. Immediate corrective actions by the licensee included initiating a plant shutdown from full power at 12:01 p.m. , and isolating the leaking blowdown line from the S/G. Appropriate TS action statements were identified and being followed. At 11:50 p.m. , the plant entered Mode 3 (Hot Standby). A sub-sequent inspection of the blowdown line identified the leakage to be from a weld in a coupling installed during original plant construction. By 6:15 a.m. on June 20, 1986 the plant was in Mode 5 (cold shutdown).
As required by 10 CFR 50.73 (a)(2)(i)(B), the licensee submitted LER 50-29/86-006 on July 18, 1986 to document that an action statement associ-ated with Technical Specification 3.3.3.1 could not be implemented. This
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was the result of the isolation of the blowdown line causing the No. 3 blowdown monitor to become inoperable from the loss of the effluent flow-path. This action also precluded im'plementation of the action statement requirement to place in service within 8-hours a temporary continuous monitor upon the loss of the blowdown monito Both prior to and subsequent to the identification of the cause of the leak that had occurred in the VC, the licensee demonstrated a conserva-tive approach to plant safety and operations. This was indicated by the
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following licensee actions: 1) containment leakage trending was being performed, with plant management monitoring the situation for potentially adverse conditions; 2) increasing leakage indication resulted in chemis-try analysis to confirm that the leakage was not primary coolant; 3) upon failure of equipment isolation techniques to identify the source of the leakage, a containment inspection was performed; and 4) the plant was placed in a shutdown condition to facilitate the conduct of the repairs in a reduced radiation environmen Upon determining that a shutdown condition was warranted, the licensee implemented its outage management approach to the planning and control of activities associated with the extended maintenance outage. The in-spector observed that the licensee's actions in this area to be effective and is attributable to a high level of involvement by senior station managers in day-to-day activities. The outage became increasingly more difficult to manage because of other events that occurred as will be discussed below. A plant startup was initiated on July 1, 1986, with the plant being successfully placed on-line on July 3, 1986. With regard to the repair and retest of the blowdown line on the No. 3 S/G, no deficien-cies were identified by the inspecto Identification of Inadequacy in ECCS Bus Power Supply At 4:35 p.m. on June 18, 1986, the licensee notified the NRC that recent electrical studies being conducted by YNSD engineers had identified the potential for overloading a station service transformer. This overload could occur during plant startup or shutdown operations during which time 2 of the 3 480V a-c station service buses are cross-tied, and a safety injection (SI) initiation occurs. This potentially results in not meeting the minimum starting voltage for the High Pressure Safety Injection (HPSI) Pumps from the offsite power source and for overloading 480V a-c station service transformer (either No. 5 or No. 6 depending on the specific crosstie configuration employed). This condition would not have affected the ability of the emergency diesel generators to supply the ECCS loads. This condition, however, was not consistent with a licensing criterion (GDC-17) due to the onsite electric distribution system having insufficient capacity that would result in the potential need for diesel power in lieu of offsite powe Immediate corrective actions initiated by the licensee on June 18, 1986, which coincided with an on going plant shutdown but were available for use prior to entering into the operational region of concern, included
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the development and issuance of procedure OP-2512, Rev. O, Operation of the 480 Volt Station Buses. This procedure specified the compensatory actions required of an additional dedicated licensed operator stationed in the control room during bus cross-tie operations. The procedure was released to plant operators by Special Order (S.O.) 86-68 issued on June 38, 1986, which also stated that training in the purpose and use of OP-2512 was to be conducted by operations department support staff as part of the operators assuming their shift duties. The inspector noted that between 0:45 p.m. and 10:20 p.m. on June 18, 1986, with the buses in a cross-tied configuration, the additional dedicated operator was assigned to the control room. The actions taken by the plant staff were consistent with tte Manager of Operations (M00) Directive 86-2 issued on June 18, 198 On June 19, 1986 the inspector attended a meeting with licensee engineer-ing ana plant personnel to review event details, proposed operating and equipment modifications, and current licensing issue At this time the inspector, as well as some of the plant personnel, ex-pressed concern for an apparently unnecessary requirement to have the dedicated operator trip the 2400 V a-c and 480V a-c bus breakers involved in the cross-tie. M00 Directive 86-3 was issued on June 26, 1986 that removed the unnecessary requirements and resolved the inspector's con-cerns. This was reflected in S.0. 86-71 issued on June 26, 1986, which also listed the 13 procedures revised to reflect the revised M00 Direc-tive 86-3. The long term corrective actions proposed by the licensee in-volves the installation of a new 2400V a-c breaker between station ser-vice transformer SST No. 4 and 2400V a-c Bus No. 1 at the next scheduled refueling (May, 1987). This action was committed to in licensee letter FYR 86-056 of June 19, 1986 to NRC:NRR and LER 50-29/86-07 issued on July 18, 1986. In a meeting between the licensee and NRC staff, which was held in Bethesda, MD on June 23, 1986 and documented in a meeting summary issued by the NRC:NRR on June 27, 1986, the NRC staff concluded that the immediate and long term corrective actions taken by the licensee to re-solve the undervoltage problem were acceptable. It further noted the need for the licensee to update the docket with a revised report on the ade-quacy of station electric distributiol voltages and highlight those as-pects that have changed since the staff's July 13, 1981 evaluation on this subject was issued. The licensee provided the revised report in it's transmittal letter FYR 86-080 to NRC:NRR on August 29, 198 Based upon the inspector's review of the event details and licensee ac-tions the following findings were made:
(1) Licensee evaluations involving full power LOCA, small break LOCAs, and steam line break analyses were determined to bound the bus-tie operation that could result in ECCS flow being delayed due to an undervoltage conditio w
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(2) Plant staff corrective actions were aggressive in resolving the im-pending operational concerns brought about by the plant shutdown on June 18, 1986. However, the situation was unnecessarily exacer-bated by the failure of the YNSD Yankee projects staff to identify and resolve the issue in a timely manner. It appears that the shut-down decision on June 18, 1986 served to act as a catalyst for the Yankee projects staff to determine that it was necessary at this time to implement corrective measures. Inspector concerns in this area, as enumerated above, warrants managements attention to mini-
,mize the necessity of imposing reactive conditions on the operating organizatio (3) LEE 50-29/86-07, and other licensee submittals to the NRC about this event, did not describe the root cause or appropriate corrective actions to preclude recurrence of this type of event. Root causes that should have been considered were 1) engineering personnel error involving the incorporation of an incorrect voltage rating for the HPSI pump motors in the 1980 voltage adequacy study, and 2) the addition of new loads to the 480 V a-c buses without upgrad-ing existing studies. The inspector addressed his concerns with the YNSD Yankee project manager at the completion of the inspection period. Although it appears that the licensee has identified pro-grammatic corrective actions in response to the above enumerated issues, they have not documented their actions to the NRC as re-quired by the 10 CFR 50.73. Accordingly, the licensee has committed to provide a revised LER for this event. Pending the receipt and review of the revised LER, the NRC's determination to treat the failure to operate the facility in accordance with General Design Criteria-17 as a licensee identified violation in accordance with 10 CFR 2 Appendix C remains an unresolved item (50-29/86-08-02).
(4) During the prior SALP Cycle the NRC identified a concern that the licensee was utilizing the S.O. process in lieu of approved plant procedures. On June 2, 1986, the operations department issued S.0, No. 86-60 to reflect the YNSD review of the 480 V a-c bus cross-tie configuration concerns and impose resulting load limits on station electrical equipment. Procedure OP-2504, Operation of the Station Power System, covers this area of plant operations, incorporates existing electrical equipment loading limits, and should have been revised at the time by the operations department. Although progress has been made in limiting the inappropriate use of S.O.s, a consis-tent level of performance in this area has not been achieved. Con-tinued management attention is warranted. Further identified defi-ciencies of this kind may result in the need for enforcement actio The inspector had no further questions of the licensee as a result of reviewing this even _- - -
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17 No. 1 Main Coolant Pump Suction Valve Stem Failure On June 19, 1986, with the plant in Mode 3 (Hot Standby) and cooling down to Mode 5 (Cold Shutdown), the plant operators observed that the No. I main coolant system (MCS) loop was indicating abnormally low flow and low main coolant pump current. Main coolant pumps at the time were being periodically rotated to allow the reactor vessel head to evenly cool down as specified in Procedure OP-2105, Rev. 26, Plant Cool down from Hot Standby. The control room operators immediately shut the' pump off. Main-tenance Request (MR)86-931 was issued to document the abnormal equipment operation. As a result of an investigation being conducted into the problem on June 22, 1986, the licensee discovered, and reported to the NRC, that the stem on the No.1 loop hot leg isolation valve, MC-MOV-325, had separated from the disc. During MCS pump rotations the valve disc had apparently jarred itself free, and dropped into a partially closed position, causing the observed conditio The failed valve is a Westinghouse 20 inch split-disc gate valve, with the combined weight of the disc and stem being approximately 450 pound The stem had sheared at a section change, which was provided as a back seating feature for the valve and represents an obvious stress concen-tration area. Corrective actions implemented by the licensee in response to the event included 1) installing a spare stem, 2) investigate the valve's torque and limit switch operation, 3) perform examination of the valve stems and 4) provide an evaluation of the principal failure mode of the valve ste The repair to the MC-MOV-325 valve would involve emptying the pressurizer, lowering the MCS level to just above the top of the MCS piping in the loops, and disassembly of the valve which would result in an unisolable 20" opening in the MCS piping. The licensee identified operational con-cerns relative to monitoring and maintaining a constant MCS level to prevent either a spill within containment or the loss of shutdown cooling (SDC) system suction. The Decay heat generation rate of the time was 150 degrees per hour. As a result of a thoroughly preplanned and controlled repair activity the inspector noted the following licensee actions that were part of their repair plan:
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Repairs were first implemented on a 2" charging line isolation valve CH-MOV-524. Because repair to this valve provided very similar operational constraints as the MC-MOV-325 valve did implementing this repair provided a greater assurance that the controls estab-lished for the 20" valve would perform as envisione Procedure OP-2119, Rev. 7, Preparation For Maintenance And/0r In-spection And Return To Service Of Unisolable MCS Components, was implemented following a detailed PORC review. Normally this proce-dure requires no pre-implementation review because it is a fill-in-the-blank type of station procedure. Information to be provided by the cognizant station personnel controlling the work activity in-i
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volves: prerequisites, precautions, system isolation instructions, vent-drain and purge instructions, system fill and vent instructions, etc. Notable precautions and prerequisites implemented by the lic-ensee were: 1) stationing dedicated operators in the loop areas who have direct communications with the control room and are to monitor local level indicators placed in service for the repairs and monitor the MCS openings for spill or loss of SDC system suction conditions; 2) stationing a dedicated operator near the SDC system pump who has direct communication with the control room and will monitor the system for a loss of suction condition; 3) stationing a dedicated operator in the control room to monitor system levels and SDC system flow; 4) all dedicated operators assigned to the various tasks re-ceived pre-activity briefings by station management personnel, with the review of appropriate emergency and operational procedures being a required part of the assignment and 5) requiring the establishment of containment integrity during the conduct of the repair activitie Although the above enumerated actions are not an exhaustive list of the licensee's corrective actions in response to this event, they are repre-sentative of a conservative, technically sound, and thorough approach to resolving conditions where the potential for safety significance ex-ists. Inspector comments relative to this event that involve radiological controls are contained in Section 5 of this Inspection Report. Regarding the failure mechanism of the valve stem, the licensee in a preliminary evaluation attributed it to a long term crack initiation and propagation process that had occurred until a depth of 1 1/4" was reached. A more detailed laboratory analysis of the failed component is being conducte Ultrasonic examination techniques were developed and used to assess the integrity of the new valve stem and the seven remaining valve stems. The inspector had reviewed this activity and concluded that there is reason-able assurance that a similar situation does not exist. The inspector noted that on June 3, 1986, the plant operators were backseating valve MC-MOV-325 and observed both a loss of position indication and that the motor would not stop. The licensee at the time was of the belief that this was a control circuit malfunction and issued MR 68-822. The licensee has stated that the existing plant accident analysis bounds this even The inspector identified no deficiencies in licensee activity associated with this even d. On June 26, 1986, the licensee identified a condition involving the in-stallation of incorrect overload trip coils installed in power supply circuit breakers for valves in the reactor coolant vent and emergency feedwater systems. This event was the subject of a special NRC Inspection, 50-29/86-0 e. Potential Loss of Shutdown Cooling At approximately 11:50 p.m. on June 26, 1986 with the plant in Mode 5, control room operators (CRO) observed that the pump seal tank, which supplies seal water under pressure to the SDC pump and the low pressure
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surge tank (LPST) cooling pump began to lose level. It was subsequently determined that that the SDC pump's shaft seal had failed. This resulted in the plant operators initiating a transfer to the alternate SDC mode i at approximately 1:05 a.m. on June 27, 1986. The SDC pump was secured
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- and the LPST cooling pump started at 1:24 a.m. and 1:37 a.m., respec-tively. Attachment C to procedure OP-2162, Rev. 14, Operation Of the SDC
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System, was in use at-the time.
- Upon starting the LPST cooling pump the CR0s observed that pressurizer-i level indication-had dropped quickly from 300 inches to an off scale low condition and MCS pressure had decreased from 100 psig to 10 psig. Imme-diate corrective actions consisted of securing the LPST cooling pump and j- having the primary auxiliary operator (PAO) isolate the flow path. The
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CR0 started all three charging pumps and restored pressurizer level and i pressure to 300 inches and 100 psig, respectively by 1:54 a.m. , the SDC j system was in operation with the use of the SDC pump. A satisfactory j completion of placing SDC in the alternate cooling mode was accomplished
- at 2:31 a.m. on June 27, 1986.
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} The licensee's investigation of this event attributed the cause of occur-l rence to personnel error by the PA0. As part of implementing the alter-i nate SDC valve line-up required by procedure OP-2161, the PA0 failed to
- fully close the LPST cooling' pump suction's manual valve CH-V-654. This i valve was found open a couple of turns. The licensee had determined that j approximately 2000 gallons of main coolant was drained from the pressur-l izer. However, the licensee had determined that the pressurizer did not 1 empty, as evidenced by the licensee's subsequent venting of the main
,. coolant loops which verified that a water-solid condition was maintained.
! Operator actions in response to this event prevented the main coolant
loops from being drained with a potentia 1Lloss of SDC system suction from i occurring. In no case would the core have been uncovered. The inspector
! noted that the' maximum incore thermocouple during this event was indi-l cating 145*F. Although this event was not of major safety significance, j the canned rotor main coolant pumps (MCPS) cannot withstand a vacuum and j failure to terminate the event in a timely manner represented potentially severe economic repercussions. Significant licensee corrective measures
- were instituted to provide proper assurance that the integrity.of the
! MCPS had not been compromised.
l No inspector identified deficiencies occurred as a result of the licen-
! see's response to this event. Proper corrective actions were implemented
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by the plant to provide management awareness of this event to all plant operators, and to insure that they recognize the importance of complete j compliance with plant procedures. The inspector believes that the opera-tors actions in responding to this event was timely and appropriate. In-spection findings pertaining to the failure of the licensee to make a l
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timely ENS notification for this event are discussed in Section 6 of this report.
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I 20 i Inadvertent Actuation of Cardox System for Manhole No. 3 While attempting to de-energize the cardox system for manhole No. 3 for the maintenance department, a plant auxiliary operator inadvertently actuated the system at 9:35 a.m. on September 23, 1986. The system was being removed from service to allow the rerouting of utilities within the manhole located in the diesel generator / safety injection buildin Engineering Design Change-Request 86-308, Rerouting of Utilities for the
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PAB North Wall Seismic Upgrade, specified the work to be performed, with the activities in the manhole to be controlled, in part, by procedure OP-5631, Revision 7, Removal and/or Installation of Fire Barrier Technical Specification 3.7.10.3 allows disabling of the automatic in-
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itiation of this high pressure carbon dioxide cardox system to facilitate maintenance activities within the manhole. The inspector verified that i the licensee had implemented the appropriate TS action statements in
, response to this event.
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i The inadvertent initiation appears to be traceable to confusion on the part of plant operators as to how the system was to be de-activated.
, Switching and Tagging Order 86-749, issued on September 23, 1986 by the l shift supervisor, specified that both the main and auxiliary storage
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bottles of the system were to have their bottle isolation valves tagged close However, the bottles did not have isolation valve An operat-ing instructions plaque (provided by Cardox) mounted on the piping ad-
- jacent to the cylinders specified that for direct manual operation the l pin was to be pulled and the valve opened. The auxiliary operator, in accordance with the directions given him by the control room, pulled the pin and closed the-valve. This action initiated the system. As this
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activity was taking place, a maintenance department worker who has had
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experience with isolating the system for the performance of routine sur-veillance activities, and for whom the tagging order was issued, was enroute to the area to aid in tagging out the system.
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The maintenance department's procedure OP-4561, Revision 2, Cardox Fire i Extinguishing System Inspection, provides written instructions, with i signoffs on how to isolate the bottles without their activatio Suit-I able precautions are also included to protect personnel from the poten-l tial of escaping gas. This procedure was not being utilized by the
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operations department. The inspector also noted that procedure OP-2707, 1 Revision 12, Operation of the Fire Suppression Systems, covers the opera- '
! tion of the system, and provides guidance to the plant operators on how to isolate and tag out the system prior to personnel entry into the man- .
hole. No personnel protection instructions are included in this proce-
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! dure. The guidance of this procedure was apparently not utilized by the l
. plant operators in tagging out the syste <
l To preclude recurrence of this event, the operations department has in-itiated the development of a sign-off type procedure that will be used
! by plant operators to effect cardox system isolation. The failure of
operations department personnel to implement the guidance contained
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' within plant procedures, as evidenced by the improper system isolation
- attempt, is a weakness that needs to be addressed by the operations de-partment managers to preclude recurrence. In addition, improvements are
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needed in the area of interdepartmental coordination between the opera-
tions and maintenance departments which would insure that activities are-I thoroughly preplanned and executed to avoid unnecessary impact on pro-tective system i
'Sub:equent to the system's discharge, and following a determination of habitability, the inspector entered the manhole and observed no obvious signs of equipment degradation. The licensee conducted their own as-sessment and concluded that the event did not adversely impact the in-
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stalled equipment. The system was returned to service at 2:20 p.m. the day of the event, following the performance of applicable portions of procedure OP-4644, Revision 10, Functional Test of the Fire Detection Instrumentation, and the performance of OP-4561.
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The inspector reviewed the licensee's. fire protection training program, which is specified in procedure AP-0503, Revision 8, and noted that plant i
fire brigade personnel receive classroom training on installed fire pro-I
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tection systems, with periodic refresher training sessions held to repeat the classroom instruction over a two year period. Essentially, once each quarter of a year one-eighth of the initial classroom training is pro-
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vided to the fire brigade member The auxiliary operators are members of the fire brigade, with the individual involved in the event last re-ceiving training on the cardox system nearly two years ago.
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The responsibility for the training is designated in procedure AP-0550, Revision 2, Fire Protection Plan, as being assigned to a training co-
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ordinator, with the development of the fire training requirements being the responsibility of the plant's fire protection coordinator (FPC).
In actuality, it is the FPC who performs the function of the training l coordinator. From a discussion held with the FPC, the inspector learned 3 that there is no training effectiveness assessment conducted (e.g., writ-ten quizzes on classroom or field walkthroughs) by either the training
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department or the FPC following training activities. In addition, the i inspector noted that the section on fire protection in the systems train-
! ing manual issued to the plant operators has not been developed, and the
! classroom training provided to R0 and SRO candidates on fire protection
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system knowledge is of insufficient detail to have precluded this event.
' Starting in 1987, the FPC plans to provide four hours of classroom train-ing on fire systems during the licensed operator requalification progra Currently, the training department's only involvement in the area of fire protection training appears to be limited to receiving and storing re-
- cords of training provided by the FPC. Licensee management attention
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is warranted to increase the scope of involvement by the training depart-
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ment in this area, and insure that they provide the proper assessment of fire protection training effectiveness.
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The inspector had no further questions on this event at this time, and
, will review the licensee's planned issuance of a Plant Information Report j on this event during a subsequent facility inspection.
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22 Plant Scrams Due to Low Control Air Pressure and Operator Error At 9:17 a.m. on October 4, 1986 with the plant at 100% of rated power, a low control air pressure condition occurred due to the malfunction of the station's main control air compressor (No. 3). This resulted in a lock-up of all four Bailey main feedwater regulator valves. Annunciator T-B5, Control Air Header Low Pressure, was received at 75 psig, and fol-
- lowed a short time later by the activation of annunciator T-835, Bailey ( Valve Position Lock. The plant operators immediately initiated an in-vestigation for a potential airline ruptur As required in the alarm response procedure for annunciator T-85, the dryer bypass solenoid was verified to have opened at 60 psig, the standby air compressor was veri-fied to auto start, and the service air compressor was started and valved into the control air system. The operators noted that the backup control air compressors (Nos. 1 and 2) were not functioning adequately _to buildup and maintain pressure by themselves. The licensee attributes this con-dition to equipment aging and has identified the need to install new equipmen Following the return of control air pressure to normal, the feedwater regulator valves were reset from the lock-up condition. At this time, the No. 1 steam generator (SG) level had decreased below the scram set-point (-10.5" setpoint on the narrow range channel with a 2-out-of-4 SG low level logic necessary for the plant scram), with the No. 2 SG level increasing slowly and the other two SGs maintaining a constant leve Prior to returning the Bailey valves to the auto position, an auxiliary operator was sent to adjust the No. 1 Bailey valve, which then started to turn level upward in the No. 1 S Once the control air pressure reached approximately 75 psig, the auxiliary operator was instructed to place all the valves in the Auto position. However, the control room feedwater station controllers were set for manual operation, and after the valves were reset locally, the level in the No. 2 SG rapidly de-l creased to the scram setpoint and a plant scram occurred.
- Maintenance Request No. 86-1395 was issued to evaluate the failure of the No. 3 control air compressor to load properly. The maintenance de-
, partment determined that pressure switch CA-PS-453 had malfunctioned.
l The switch was removed and replaced with_a bench-calibrated replacement unit, with the air compressor verified to function properly. No addi-tional equipment or operating abnormalities were identified by the lic-ensee as a result of plant or operator response to the reactor scra Following the completion of the post trip review process performed in l accordance with procedure AP-2003, and the conduct of a hot leak inspec-l tion in the vapor container, the plant was started up from Mode 3 at i 8:35 p.m. on October 4, 1986. Subsequently at 11:09 p.m. , as indicated on the sequence of events recorder printout, an automatic reactor scram j
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occurred when the control room operator inadvertently positioned one of the two non-return valve (NRV) trip / reset switches to the trip positio This switch when placed in the trip position provides an input, by design,
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that causes an automatic reactor scram. At the time the steam lines were being warmed up, and as part of opening the NRVs, the logics were being reset. There appears to be some concern on the part of the plant opera-tors that reset versus trip positions on the switches are contrary to that which exists for other plant systems and represents a human factors consideration. However, the inspector noted that the switch is plainly marked as to the function provided by the respective position As part of the inspector's review, it was determined that the control room log and completion of the post trip review documentation was in-accurate, in that the scram was noted as occurring at 11:15 p.m. -The reactor engineering manager (REM) verified for the inspector that (1) the actual scram time was 11:09 p.m., and (2) the entire review pro-cess, including the PORC, had failed to identify the discrepancy. The REM indicated that he had already planned on taking corrective action for other reasons related to the post trip review process that would improve the documentation aspects of the revie He acknowledged the inspector's comments and concerns for the lack of attention to detail on something as important as the time that a plant scram occurs. A plant startup was initiated at 12:00 a.m. on October 5, 1986 with the plant on-line at 7:22 a.m. the same day, with licensee plans to increase power level to 100% of rated power following fuel conditioning constraint Following the initial plant trip on October 4, 1986, the main coolant dose equivalent iodine level (DEI) reached a maximum level of 86% of the TS limit. Increased purification flow was used to reduce the DEI level in the main coolant system. The licensee is watching the fuel perform-ance carefully to assess and compensate for what appears to be continuing fuel cladding degradation in second cycle fuel pins that occur following plant trip The licensee had identified and performed all TS related surveillances required by the increased DEI level The above enumerated events, and corrective actions, will be reviewed during a subsequent inspection following the licensee's submittals of LERs that are required by 10 CFR 50.7 . Maintenance Observations The inspector observed and reviewed maintenance and problem investigation ac-tivities to verify compliance with regulations, administrative and maintenance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualification, radiological con-trols for worker protection, fire protection, retest requirements and report-ability per Technical Specifications. The following activities were included:
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Maintenance Request (MR)86-863, Loop No. 4 Bypass Valve MC-MOV-504 Hot Stem Leakoff
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MR 86-987, No. 3 S. G. (Steam Generator) Emergency Feed Line/ Blowdown Line Leak
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MR 86-931 & 86-933, No. 1 Main Coolant Pump Low Flow & Low Amperage
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MR 86-947 & 86-948 Control Room Emergency Air Cleaning System (CREACS)
Fans FN-9-1 and FN-9-2 Motor Starters in EMCC-5 & 6, Respectively, Tele-mecanique 10 CFR 21 Notification Dated May 14, 1986
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MR 86-962, Replace Breaker Overload In valve PR-MOV-558
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MR 86-963, Replace Breaker Overload In valve VD-MOV-559
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MR 86-964, Replace Breaker Overload In valve VD-MOV-557
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MR 86-965, Shutdown Cooling Pump - Leaking Seal
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MR 86-1251, Panalarm NC-9 "M.C. Pressure C1. Inst. Test" Does Not Operate From Loop 1 Test Switch
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MR 86-253, Incore Wide Range Thermocouple Readouts
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MR 86-638, A-5 Incore Thermocouples MC-TI-I And MC-TI-226 Discrepancies
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MR 86-971, Discrepancy In Point D-8 In SPDS Incore Thermocouple Display Map Based upon a review of licensee activities in this area the inspector noted the following: Regarding MRs86-253,-638, and -971, the licensee has been experiencing discrepancies between various readouts for some of the thermocouples in
, the inadequate core cooling thermocouple system. Licensee personnel in the control room have been properly aware of the off normal conditions, and have been pursuing corrective action by submitting MRs. The I & C department has been following up with troubleshooting activity. On Sep-tember 4, 1986 the inspector reviewed the I & C department's trouble-shooting activity and noted that a Lifted Lead Request (LLR) form, APF-0018.4, was issued to control the activity. The form specified that "one-at-a-time" the incore temperature signal leads at terminal strips in the safety parameter display system cabinet may be lifted. A total of 66 leads including ground wire, could have been affected by the authorized LL The LLR, which is governed by procedure AP-0018, Rev. 11, Jumper and Lifted Lead Control, requires recording dates, time, and personnel in-volved for the lifting and restoring of the leads. The technicians in-volved in the process were not recording the necessary documentation on a wire by wire basis. Inspector concerns were immediately brought to the
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E i attention of the assistant I & C department supervisor. Action was taken I to provide full documentation for each lead lifted. A total of 6 leads
, were lifted and subsequently documented by the license This item was discussed with the I & C department supervisor, who indi-l cated that they do not provide full documentation required of a lifted j lead on a wire-by-wire basis when performing non-safety related trouble-l shouting. Essentially, the documentation provided in this case is repre-sentative of the first lifted wire and last wire restored. All wires,
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- however, are identified as having permission to be lifted by the pre-
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planned review for the LLR. For the case of safety related troubleshoot-ing, the I & C department supervisor indicated that it is their policy
- . to provide full documentation, including independent verification, on-a wire-by-wire basis. Procedure AP-0018 indicates that it provides the
- management controls to ensure that lifting of electrical leads will be
, properly documented. The documentation approach of safety vs non-safety
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lifted leads is not specified in the procedure. Inspector concerns deal
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with an apparent lack of clear procedural instructions that would reflect I
the licensee's policy on documenting non-safety related troubleshooting
!- lifted lead activity. The inspector requested that the licensee evaluate i this item to ascertain whether the procedure, the practices, or both
- require modificatio !
The licensee's practices associate with lifted leads and jumper controls
- will be reviewed in future routine facility inspections. The inspector
- had no further questions on this item.
I On May 23, 1986, the plant staff received a 10 CFR 21 notification from j the Telemecanique Corp. dated May 14, 1986 which stated that previously
. purchased motor starters have a potential defect involving latch cams.
i According to Telemecanique, should the circuit breaker portion of the
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motor starter trip on overload, it is possible that the breakers could
- not be reset. NRC:RI was notified pursuant to 10 CFR 21 on May 2,1986
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l by Telemecanique. On June 16, 1986 the maintenance support department
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(MSD) issued their evaluation of the notice in Memorandum MSD 29/86, and found that the motor starters in EMCC-5 and -6 utilized for the control room emergency air cleaning system (CREACS) fans were affected. Accord-ingly, MRs86-947 and 86-948 were issued to control the work associated
. with replacing their latch cams. The licensee's evaluation indicates that the CREACS System is operable with the defect. The CREACS is a safety i related system whose operation is described in plant emergency procedure Currently, the plant TS do not cover the operation of the CREACS.
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The licensee initiated purchasing of the replacement parts by issuance of a Material and Service Purchase Request on June 17, 1986. Following
the YNSD operations and engineering department reviews, a purchase order
- was issued on July 10, 1986. Subsequently on August 1, 1986 the replace-l rient latch cams were received at the plant. However, documentation from i Telemecanique specifying that the parts are commercial grade items caused further delay because the licensee's purchase order requirements speci-
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fled 10 CFR 21 notifications were required. The parts were finally ap-proved for use on September 3,1986. As of September 10, 1986, the lic-ensee had no immediate plans for installing the available replacement parts. Tracking to resolve the 10 CFR 21 concern was being done by the MSD but, their work list indicated that the task was due for completion by October 31, 198 Inspector concerns were discussed with the plant superintendent (PS) on September 10, 1986 that pertained to 1) an exceedingly long time period necessary to resolve the defect due to purchasing, practices and minimal licensee followup, 2) the lack of current installation plans, and 3) an apparent failure to include the subject 10 CFR 21 notification in the operational feedback and assessment process, as controlled by AP-0020, Rev. 4 Operating Information Reviews. The PS acknowledged the inspector's comments and concerns, and indicated the issue will be resolved in a timely manner. The inspector had no further questions on this ite . Surveillance Observations The inspector observed tests and parts of tests to assess performance in ac-cordance with approved procedures and LCOs, test results (if completed), re-moval and restoration of equipment, and deficiency review and resolution. The following tests were reviewed:
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OP-4271, Rev. 1, Leakage Check Of The Neutron Shield Tank
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OP-4253, Rev. O, Safe Shutdown System Operability Test
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OP-4238, Rev. 6, Test of the Control Room Ventilation Emergency Shutdown System and CREACS Fans
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OP-4659, Rev. 9, Main Coolant System Pressure Channels Functional Test
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OP-4210, Rev. 17, Fire System Operability Test
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OP-4211, Rev. 18, Emergency Feedwater System Operability Test
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OP-4212, Rev. 2, Main Coolant System Residual Heat Removal Availability Verification
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OP-4272. Rev. O, Accident Monitoring Instrumentation Channel Check Based upon a review of the licensee activities in this area, the inspector noted the following: During the performance of OP-4659 on August 28, 1986, the surveillance test identified that No. 1 main coolant system pressure channel test switch (MC-TS-100) did not annunciate when the instrument channel was in the test mode. This deficiency and actions to be taken were recorded appropriately in the procedure. The licensee issued MR 86-1251 on August i
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28, 1986 to initiate corrective actions but, due to the need to make various safety system trip functions inoperable during the repair (in-cludes Safety Injection Initiation from one of the two trip channels)
the licensee has prioritized this repair for a plant shutdown. This ac-tion was determined to be appropriate by the inspector because of other procedural constraints which ensures that the channel will not be inad-vertently left in a bypassed or tripped condition following the perform-ance of the surveillance test. In addition, the I & C department super-visor has directed that the unused procedures on file will be marked to instruct I & C personnel to inform control room personnel of the defi-ciency each and very time the procedure is implemented. This will aid the plant operator's in being aware of the equipment proble As a result of reviewing the licensee's implementation of procedure OP-4272, the inspector noted on September 3, 1986 that major inconsistencies Oxisted between the Technical Specification 3.3.3.5 requirements for accident monitoring instrumentation channel availabilities, and those enumerated in the procedure. This was brought to the attention of the operations department managers by the inspector on September 3,198 The operations department revised procedure OP-4272, which received PORC review and approval on September 9, 1986. The inspector noted that the licensee's corrective actions were responsive to NRC concerns and per-formed in a cooperative and timely manne Inspector observations pertaining to the performance of TS surveillance requirements during Mode 3 implemented by the Operations Department is discussed in Section 3 of this report as part of determining the status Unresolved Item 50-29/86-05-01. However, the inspector's finding per-taining to the Unresolved Item and procedure OP-4272 inadequacies dis-cussed above, strongly suggests that additional licensee management at-tention is warranted to insure that the operations department's activi-ties and procedures are correctly incorporating and implementing re-quirements of the T The inspector had no further comments or identified additional discrepancies in this are . Bimonthly Safety System Walkdown The inspector independently verified the operability of a selected engineered safety feature (ESF) system by performing a complete walkdown of the access-ible portions of the system to:
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Confirm that the licensee's system lineup procedures match plant drawings and the as-built configurations;
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Identify equipment conditions and items that might degrade performance;
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Inspect equipment and cabinets for abnormal conditions;
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Verify power valve position, availability for function and position in-dication; and
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Verify compliance with Technical Specifications requirement g The emergency feedwater (EFW) system was examined. EFW operability require- ,
ments were verified in accordance with the applicable TS. Discussions with plant operators indicated that they were fully knowledgeable of the system design and operation. Good housekeeping practices were evident throughout the inspection. System and instrumentation valves were verified to be in proper
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positions, and local versus remote valve position indications were also veri-
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fled. Some procedures which were reviewed prior to system walkdown were in-consistent with respect to the specification of various valve positions. The procedural discrepancies were identified and immediately investigated and i
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corrected by the licensee. The discrepancies may be attributed to inadequate procedure review (see Section 13 details for description of the problem and
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licensee planned corrective actions). No further discrepancies were identified
- during the walkdown.
1 1 Onsite Review Committee Activities
On June 18, 21, 25, 28, and July 1 and 28, 1986 the inspector observed the meetings of the Yankee NPS onsite review committee to ascertain that the pro-
visions of TS 6.5.1 were met.
1 No unacceptable conditions were identified.
. 1 Licensee Response to IE Bulletins
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The licensee's response to the following IE Bulletins (IEB) were reviewed.
i This review included: adequacy of the response to IEB requirements, timeliness
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of the response, completion of identified corrective actions and timeliness of completion.
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IE Bulletin No. 86-02: Static "0" Ring Differential Pressure Switches
dated July 18, 1986.~This'IEB was issued to request licensees to deter- !
mine if they have Model 102 or 103 switches installed as electrical t- equipment important to safety. The licensee was to report within 7 days '
the extent to which the switches were installed.
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The inspector reviewed licensee letter FYR 86-068 to NRC:RI dated July
- 23, 1986. This letter stipulated that the licensee had reviewed their l
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installed equipment lists and stockroom inventory at the plant and found no differential pressure switches to have been supplied by SOR, Incor-
] porate This bulletin is close .
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IE Bulletin No. 85-01, steam binding of emergency feedwater (EFW) pump This bulletin was issued to inform licensees of serious safety problems which occurred at certain operating facilities concerning the inopera-bility of EFW pumps due to steam binding. The licensee was requested to:
(1) develop procedures for monitoring fluid conditions within the EFW system on a regular basis during the time that the system is re-quired to be operable; (2) develop procedures for recognizing steam binding and for restoring the EFW system to operable status, should steam binding occur; (3) the procedural controls were to remain in effect until completion of hardware modification to substantially reduce the likelihood of steam bindin The inspector reviewed the licensee's response to IE Bulletin 85-01, letter No. FYR 86-011, dated January 30, 1986. The licensee monitors the EFW fluid conditions by verifying (by touch) that the EFW pump discharge piping is maintained at ambient temperature. This is performed each 8-hour shift and recorded on both the primary and secondary operator log sheets for the two motor driven pumps and one steam driven EFW pump, respectively. Procedures for recognizing steam binding and for restoring the EFW system to operable status do not exist. However, the licensee stated that operator training covers steam binding and restoration of pumps, although not specific to the EFW pumps. While interviewing selected reactor operators, all demonstrated an acceptable knowledge level of recognizing steam binding and pump restoration. The inspector expressed a concern about providing procedural instructions to the opera-tors to immediately notify the shift supervisor upon discovery of a high temperature on the EFW pump discharge piping during shift monitorin The licensee agreed to provide the necessary procedural controls in a plant procedure that will be responsive to the inspector's concerns. The licensee maintains that the EFW system configuration and operator sur-veillance makes steam binding of the EFW pumps a highly unlikely event, and that steam binding would not disable all emergency feed capabilit The inspector had no further question This bulletin remains open pending the licensee's incorporation of the enumerated inspector concern into a plant procedur . Plant Procedures Program The inspector conducted an inspection of the licensee's plant procedures program to determine: (1) whether overall plant procedures are in accordance with regulatory requirements; (2) whether temporary procedures and procedure changes are performed in accordance with TS requirements; and (3) whether the technical adequacy of reviewed procedures is consistent with the desired ac-tion . . -. . . - - - -. - - - _ - - . . . . - _--- - ..
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} The wide range of' plant procedures were selected to verify that their review i and approval were in accordance with TS. Specific TS' amendments were reviewed i along with the affected plant procedures to determine whether the appropriate j procedural changes were made. Procedures were reviewed to verify overall pro-
cedure content consistent with TS requirements. The technical content of safety related procedures was also reviewed. Additionally, temporary and per-manent procedure changes and their incorporation into procedures and the bi-annual procedure review program were reviewed.
i The inspector noted that the plant procedures are generally acceptable in
content. They provide helpful basis and discussion sections to those who use the procedures. There were, however, several discrepancies identified of which
- - almost all involved the responsibility of the Operations Department.-The lic-i ensee previously committed to provide for double verification of all safety--
i related system lineups. It was not clear from the review whether all safety-
! related system lineups were independently verified. Some procedures which in-
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clude system lineups contain only one signoff block on safety related systems,
- thereby not meeting their commitment. However, there are additional procedures
- which contain the same system lineups, and if performed in conjunction with
the first lineup, and by an independent individual, independent verification -
, is achieved.. Appropriate administrative controls were not evident-to ensure
!. that two procedures be performed, if required. Additionally, the two proce-dures must reference each other if performance of both procedures represents ,
j a condition to meeting the independent verification commitmen ,
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Many procedures contained minor errors and misleading instructions. The lack
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of clear, concise instructions may lead to confusion, and potential system I misoperation. There were also some procedures which contained valve lineups
} which were inconsistent in that two different procedures called for the same i valve to be in a different system configuration in the same mode. A biennial j procedure review program exists to upgrade and revise all plant procedures.
- The procedural discrepancies identified are indicative of an inadequate pro-
cedural review program. The inspector discussed each of the procedural dis-
. crepancies with an appropriate licensee representative. The licensee indicated-l- that corrective actions would be implemented.
t l The procedure for plant procedures (AP-0001) specifies requirements'for pre-paration, review, approval and revision of plant procedures. There are several i mechanisms through which procedures may be revised. The instructions provided i are very confusing and hard to track administratively. However, AP-0001 is j currently undergoing a significant revision to reflect the upgrading of the entire procedural change and control program.
j The inspector noted three primary concerns:
- An apparent lack of independent verification control for all safety-related system lineups
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4 Procedure review program lacks emphasis of attention to detail for the
- review and approval process
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- - 31 Inadequate procedural change program l- Licensee resolution of these concerns will be reviewed during routine inspec-tions at the facility.
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1 Emergency Planning Drill
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The inspector participated in the review of the licensee's emergency drill j wnich took place on June 11, 1986. This review included three major areas:
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drill preparation / review of scenario I --
drill observance
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review of licensees critique / presentation of HRC findings The details of tee inspector's comments and findings were presented to the
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NRC:RI team leader and is described in NRC Inspection Report No. 50-29/86 0 . Licensee Response to Selected Safety Issues (TI 2515/77)
During this inspection period, as requested by the NRC's Office of Inspection
. and Enforcement (IE), a region-based inspector conducted a survey of the lic-ensee's response to selected safety issues (reference: IE Manual Temporary Instruction 2515/77). The primary purpose of the survey was to determine the actions that licensees are taking to address a selected sample of safety is-sues. These issues have been identified in IE bulletins, circulars, and in-formation notices and in the Institute of Nuclear Power Operations' (INP0's)
, significant operating event reports (SOERs). This information is needed to 1 determine whether the NRC should take additional action on these items. A secondary purpose of the survey was to determine the actions that licensees are taking in response to INP0's SOERs. It should be noted that INP0's re-commendations are not regulatory requirements and that this survey did not involve checking responses simply because they are INPO's recommendation Key items that are central to resolving safety concerns were selected for this '
- survey.
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The selected safety issues applicable to the survey at Yankee Nuclear Power l' Station were related to biofouling of cooling water heat exchangers. The in-spector determined whether equipment has been installed, surveillances are
- being performed, and training and procedures are being provided. The survey results were provided to IE for their review and assessment. No violations or safety concerns were identified as a result of this survey, 1 Fitness for Duty Concerns
- During the inspection period, the NRC became aware of an incident that in-volved the use of a medically prescribed drug that allegedly impacted on the ability of an armed security officer to perform required duties. The event
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had occurred in January 1986. A review by the inspector of event details, licensee and security contractor awareness of the event, and their resulting corrective actions did not result in identifying any violations of NRC re-quirements. However, the inspector did determine the following informatio The use of medication by the individual in question both prior to arriv-ing for duty and while on duty, did reflect a lack of good judgemen However, this condition was possibly exacerbated by contractor practices and the nature and extent of licensee overview. Following the event the individual was appropriately counselled by the security contracto The contracted security organization for the site, Green Mountain Secur-ity Services (GMSS), was aware that the individual had been medically prescribed a drug which had the potential to affect performance. However, it was not envisioned that this prescription drug would be used while on duty. Written policies and procedures pertaining to the use of medi-cation by security officers that might impair the ability to perform one's duties did not exist at the time of the event. Furthermore, there is no evidence ~that this subject was covered in employee indoctrination or training given by GMSS. A policy is being developed currently, which will include a procedure to be followed by on-shift Security Supervisors should they be informed that an individual is being allowed to work while taking medication. The contractor management has not been aggressive in pursuing organizational level corrective actions. The inspector also concluded that on the event date, the on-duty security. shift supervisor failed to immediately relieve the security officer of duty when he became aware of the fact that a prescription drug had been taken which had the potential to affect performance of dut Regarding the role of licensee oversight and responsibility, it appears that the licensee's Security Supervisor, the single licensee employee who directly supervises site security activity, did not respond promptly or aggressively, upon being informed of this matter by the inspecto Only following prodding by the inspector that additional corrective ac-tion was warranted, a written request for contractor corrective action to address the issues with security organization members occurred on June 13, 1986. As of the completion of the inspection period, the requested action still has not occurred. There is no evidence, written or otherwise, that would support the belief that the licensee exercised an aggressive overview function in response to this event. Neither had they provided timely management attention to ensure that existing company policies and practices pertaining to the use of medication while on duty were being effectively transmitted to or implemented by the security contracto Further senior station management involvement in security activities is necessary to focus attention to resolving this matte The inspector informed the licensee that the issue of fitness for duty and the resulting licensee policies being developed at this time to deal with NRC and industry concerns will be reviewed in future routine facility inspection T '
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1 Management Meetings During the inspection period, the following management meetings were conducted or attended by the inspector as noted below:
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The inspector participated in management meetings associated with the team inspection 50-29/86-06 of the licensee's Annual Emergency Plan Ex-ercise conducted during the period of June 10-12, 1986. Participation by the inspector included representing the NRC at the joint FEMA /NRC Critique Meeting held at the Rowe Elementary School during the evening of June 12, 198 Exit meeting held on July 2, 1986 by the inspector at the conclusion of Special Inspection 50-29/86-09, which resulted from the licensees deter-mination that valves in the reactor coolant vent system and emergency feedwater system were inoperabl The inspector attended on July 22, 1986 an Enforcement Conference held in the NRC: Region I Office to discuss the circumstances surrounding valve inoperability and licensee corrective actions for the event described in Special Inspection Report 50-29/86-0 The inspector participated in management meetings associated with safe-guards regulatory effectiveness team review conducted by the NRC and Army Special Forces personnel during the period July 28 - August 1, 198 At periodic intervals during the course of the inspection period, meet-ings were held with senior facility management to discuss the inspection scope and preliminary findings of the resident inspectors.