IR 05000029/1988005
| ML20154A300 | |
| Person / Time | |
|---|---|
| Site: | Yankee Rowe |
| Issue date: | 05/06/1988 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20154A294 | List: |
| References | |
| 50-029-88-05, 50-29-88-5, IEB-87-002, IEB-87-2, IEB-88-001, IEB-88-1, NUDOCS 8805130201 | |
| Download: ML20154A300 (51) | |
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b U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.: 50-29/88-05 Docket No.: 50-29 Licensee No.: OPR-3
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Licensee: Yankee Atomic Electric Company 1671 Worcester Road Framingham, Massachusetts 01701 Facility Name: Yankee Nuclear Power Station
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Inspection at: Rowe, Massachusetts Inspection Conducted: February 23, 1988 - March 31, 1988 Inspectors: Harold Eichenholz, Senior Resident Inspector Cy hia A. Carpenter, Resident Insp tor Approved "
onald R. Haverkamp, Chigf 6 h Date Reactor Projects Section N Inspection Summarn Inspection on February 23, 1988 - March 31, 1988 (Report No. 50-29/88-05)
Areas Inspected: Routine onsite regular and backshift inspection by two resident inspectors (220 hours0.00255 days <br />0.0611 hours <br />3.637566e-4 weeks <br />8.371e-5 months <br />). Areas inspected included licensee action on previous inspection findings, operational safety verification, radiological controls, events requiring telephone notification to the NRC, plant events, maintenance observations, surveillance observations, on-site review committee 't activities, licensee events reports, licensee response to NRC Bulletins, organization and administration, participation in NRR/ Licensee meeting, licen-see self assessment activities, and corporate and engineering support activitie Results: No violations or deviations were identified by the inspector; how-ever, two occasions involving the failure to verify proper operation of the emergency diesel generators (Section 7.e) and the failure to provide required postings and barricades (Section 7.1) were classified as licensee-identified violation i
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Regarding an overall facility assessment for this inspection period, the NRC has noted a generally strong performance in plant operations and supporting arca This appeared to be attributable, in large measure, to extensive licensee management involvement in day-to-day activities at all levels, and a high level of commitment by its personnel to safs operation of the plan ;
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. Inspection Summary (Continued) 2 Areas that continued to be considered notable licensee strengths include: the cooperative and responsive manner in which NRC initiatives or concerns are handled (various sections); training efforts for reactor operator trainees (Section 4); fire protection and housekeeping (Section 4); the concerned and cautious approach exhibited in dealing with the anomalous behavior of control rod position indicating lights (Section 4); the manner in which licensed opera-tors prepared for and carried out difficult plant evolutions (Section 7); the thorough and aggressive investigation and corrective measures exhibited by plant management in response to a radiological event (Section 7); corporate and engineering support for plant operations (Section 10 and 16); and the develop-ment of meaningful ways to conduct critical self assessments of perrormance (Section 15).
Areas that were considered to warrant increased licensee attention included:
the failure to ensure a proper priority for the timely conduct of maintenance on security equipment (Section 4); neither performing timely evaluations nor aggressively completing proper corrective actions for potential inadequacies, as exemplified by events resulting from reviewing a surveillance procedure (Section 7) and conducting surveillance testing on pressure switches (Section 9); ensuring the proper immediate personnel response to a radiological event (Section 7); and licensed operator attention to detail (Section 7).
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'lACLOF CONTENTS Page
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1. Persons Contacted. . . . . . . . . . . . . . . . . . . . . . . . . 1 Summary'of Facility and NRC Activities . . . . . . . . . . . . . . 1 Licensee Action on Previous Inspection' Findings (IP 92701 and- -
92702)*. . . . . . . . . . . . ... . . . . . . . . . . . . . . . 2 Operational Safety Vcrification (IP 71707) . . . . . . . . . . . . 5 l Daily Inspection. . . . . ................. 5 System Alignment Inspection . . ............... 10
' Biweekly and Other Inspections. . . . . . . . . . . . . . . . 11 Backshift Inspection. . . .................. 13 Radiological Controls (IP 71707) . . . .............. 13 Events Requiring Telephone Notification to the NRC (IP 93702). . . 14 Plant Events (IP 93702, 62703) . . . . . . . . . . . . . . . . . . 15
' Plant Load Reduction due to Water Contamination of No. 3 Boiler Feed Pump 011 Supply . ............... 15 Plant Load Reduction due to No.1 Feedwater Heater Drain Pump Pac king Leakage. . . . . . . . . . . . . . . . . . . . 16 j Load Reduction for Condenser Tube Leak Check. . . . . . . . . 17
. Plant Worker Transported to Offsite Medical Facility. .... 18 l Inadequate Surveillance of Emergency Diesel Generators. . . . 19 I Emergency Load Reduction due to Trip of No. 1 Feedwater Heater Drain Pump . . . . . . . . ............. 21 : Reactor Scram due to Loss of Power to Nuclear Instrumenta- '
tion Cabinet. ....................... 22
' Loss of Emergency Assessment Capability . .......... 23 Radiological Event: Removal of Radiation Area Barrier / '
Posting . . . . ...................... 24 Reactor Scram on Low Steam Generator (SG) Levels. . . . . . . 26 Maintenance Observations (IP 62703). . . . . . . . . . . . . . . . 28 Surveillance Observations (IP 61726, 62703). . . . . . . . . . . . 34 10. On-site Review Committee Activities (IP 40700) . . . . . . . . . . 39 1 Review of Licensee Event Reports (IP 90712, 92700) . . . . . . . . 39 I I
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.. TableofContents(Continued)
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1 Licensee Response to NRC Bulletins (IP 92703). . . . . . . . . . . 40 13. Organization and Administration (IP.35701) . . . . . . . . . . . . . 4 . Participations in NRR/ Licensee Meeting (IP 94702). . . . . . . . . ~41
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1 Licensee Self Assessment Activities.(IP 35701) . . . . . . . . . . 42- Work Activity Observation Program . . . . . . . . . .. . . . . -42 Plant Inspection Program. . . . . . . . . . . . . . . . . . . 43 Training Department Plant Observation Program . . . . . . . . 43 Observation of Licensed Operators . . . . . . . . . . . . . . 43 INPO Peer Evaluator Program . . . . . . . . . . . . . . . . . 44 Yankee Porjects Lessons Learned . . . . . . . . . . . . . . . 44
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16. Corporate and Engineering Support Activities (IP 40703). . . . . . 45 17. Open Items . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 18. Management Meetings (IP 30703) . . . . . . . . . . . . . . . . . . 47 i
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- The ,,RC Inspection Manual inspection procedure (IP) or temporary instruction (TI) or the Region I temporary instruction (RITI) that was used-as inspection guidance is listed for each applicable report sectio '
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DETAILS Persons Contacted i Yankee Nuclear Power Station (YNPS)
N. St. Laurent, Plant. Superintendent T. Henderson, Assistant Plant Superintendent R. Mellor, Technical Director Yankee Atomic Electric Company (YAEC)
J. Tribble, President J. DeVincentis, Vice President of Projects i B. Drawbridge, Vice President and Manager of Operations '
J. Haseltine, Project Manager, Yankee Project -
D. Maidrand, Assistant Project Manager, Yankee Project G. Papanic, Licensing Engineer The inspector also interviewed other licensee employees during the inspec-tion, including members of the . operations, radiation protection, chemis-try, instrument and control, maintenance, reactor engineering, security,.
training, technical services and general office staff . Summary of Facility and NRC Activities At the start of the inspection period on February 23,.1988 the plant was returning to full power operations and attained 100% of rated power that day. Plant conditions remained stable until February 27, 1988 when a con-trolled lo:d reduction was commenced to 75% of rated power due to water contamination of the No. 3 boiler feed pump oil supply. The plant re-turned to full power operations on February 28, 1988 and was maintained at ,
that power level until March 3,198 On that date, a controlled load l reduction was initiated to 75% of rated power due to a packing leak on the No. 1 heater drain pump. The plant was at 100% of rated power on March 4,1988 and was maintained at that power level until March 12, 1988 when a scheduled load reduction to 48% of rated power was commenced to plug leaking condenser water box tubes and perform other maintenance. The plant returned to full power operation on March 13, 1988 where it remained until March 16, 1988 when an emergency load reduction was initiated to approximately 73% of rated power due to the trip of the No. I heater drain pum The plant was returned to 87% of rated power on March 16, 1988 and held at that power level until March 17, 1988 when the licensee commenced a i load reduction to approximately 70% of rated power in order to perform l maintenance on the No. 2 feedwater heater drain pump. The plant was '
returned to full power operation on March 18, 1988 where it remained until March 22, 1988, when an automatic reactor trip occurred due to loss of power to nuclear instrumentation (NI) cabinet A. Following a reactor
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startup on March 24, 1988 the plant had attained approximately 86% of rated _ power when an automatic reactor trip occurred on March 26,1988 on low steam generator water level. Following reactor startup the same day, the plant attained 100% of rated power on MarU 29, 1988, where it remained until the end of this inspection perio A meeting was held ' between the President, YAEC, and the NRC Region I (NRC:RI) Regional Administrator and senior staff on February 24, 1987 at the regional office to discuss current items of interest involving manage-ment issues. On March 18, 1988, licensee representatives, including the Vice President and Manager of Operations, held a meeting with NRC:RI staff at the regional office to discuss licensee actions to improve the security program including plans for a security reorganizatio During the week of February 29 through March 4,1988, the_ Yankee Resident Inspector substituted for the Senior Resident and Resident Inspectors at Seabrook Station, Unit 1, Seabrook, New Hampshire. Two NRC Region I specialists completed an inspection in the area of emergency preparedness during the period of February 29 - March 4,1988 (Inspection Report N /88-06). During the period of March 16-17, 1988, the NRC:NRR Project Directorate I-3 Director and the assigned facility Project Manager were on-site to discuss matters of interest with the resident inspectors and the licensee's staf . Licensee Action on Previous Inspection Findings (Closed) Open Item 87-11-03: Provide management controls that will ensure that preventive maintenance inspections will be performed on pump discharge check valves at the appropriate time. The inspector held a discussion with the plant maintenance manager and determined that he concurred that :.1anagement controls need to be in place on a !
consistent basis. The maintenance foreman showed the inspector a draf t revision to procedure DP-5451, Maintenance of the Boiler Feed i Pumps, which incorporated controls that will ensure that appropriate l consideration will be given by maintenance supervision on the need to l inspect the check valve This procedure also incorporated a de-tailed check list to be used to conduct the check valve inspectio Maintenance procedures that do not currently incorporate these con-trols will be revised as the procedures come up for review or revi sio On March 14, 1988, the plant maintenance manager issued a memorandum {
to the maintenance support supervisor and the maintenance supervisor i that reflected the inspector's concerns that their existing policy l 1s not being consistently applied when performing pump maintenanc This memorandum documented the licensee's short and long term '
actions, some of which are drscribed above. The licensee's actions in the aggregate represented a timely, technically sound and thorough approach to resolve this issue.
This item is close I
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. 3 b. (Closed) Open' Item 88-01-03: Determine acceptability of licensee's schedule for conducting the next containment integrated leak rate test (CILRT). As noted in section 15 of ~ Inspection Report 50-29/
88-01, NRC:RI would review the schedule stipulated in licensee letter FYR 88-14. The cognizant NRC:RI section chief in the Division of Reactor Safety informed the inspector on March 10,1988 that the licensee's -plans to conduct the CILRT during the -refueling outage scheduled for the summer,1990 was acceptable to the NR Licensee representatives were informed by ~ the inspector that this inspection report provides the appropriate level of documentation.fo '
the NRC review and determinatio This item is close c. (Closed) Violation 50-29/87-02-02: . Inadvertent ECCS Actuation. The lic ensee responded to this violation on June 11, 1987 in letter'FYR 87-1 This response identified corrective action to preclude recurrence of this event. On February 18, 1987 with the plant being maintained in Mode 3, an inadvertent initiation -of the safety injec-tion and non-essential containment isolation systems occurred as a result of implementing maintenance activity. The details of this event are discussed in section 8 of Inspection Report 50-29/87-02, and the respective Licensee Event Report, LER 50-29/87-04, is closed i in Section 11 of this repor '
The root cause of the event was attributed to personnel error in the failure to perform an adequate review of the system design. The licensee failed to (1) detect that the implementation of the tempor-
.' ary change request (TCR) would affect an operable system, (2) ider.-
tify the applicable TS that should have been complied with and- (3)
specify the use of the safety 'njection auto / start-auto cutout switch for train A as part of the proper implementation of the TCR. The inspector also had additional concerns involving the participation of control room personnel in the review aspects -of the TCR proces As part of the licensee's corrective actions, the I&C department supervisors and technicians were instructed to thoroughly review all !
aspects of work to be performed. A special order was issued to operations department personnel to realize the importance of review-ing documents that allow work to be performed and take the necessary time for an adequate review prior to allowing work to continue. The shift supervisors were instructed to review the TCR procedure with i their crew and emphasize that whenever a review of a TCR is in ques- I tion higher management should be consulted prior to authorization of l the wor *'
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. 4 The licensee also committed to revising procedure AP-0018, Rev.14, Temporary -Change Control . The inspector reviewed this procedure and noted that the procedure delineates the responsibilities of the per-sonnel whose signatures are required prior to the work implementa-tion. The procedure notes -that operations personnel shall pay par-ticular attention to a review of the technical evaluation and tech-nical operational safety review including all applicable technical specifications, accident analysis assumptions, system interactions -
and any additional considerations, the omission of which may inappro-priately degrade system design and plant ' operations. The procedure further states that the shift supervisor (SS) has the overall authority and responsibility.to disapprove any TCR based on the eval-uation information, the lack of any information or for. any reason consistent with his knowledge and good judgment. While the SS is not expected to know the finest detail of the work activity, he should have sufficient knowledge and understanding of what effects the activity will have on plant systems and plant operations. The auth-orization of the SS to . proceed with the TCR by his signature is a statement of this knowledge and understanding, and documents that an adequate evaluation has been performed, the consequences are known and equipment operability has been adequately considered. Finally, AP-0018 was revised to include instructions that TCR's snould be questioned, and, when answers cannot be provided, the TCR should be presented to licensee management for resolution. If necessary, the TCR can be reviewed at POR The inspector considers that the revision to AP-0018 should be suf-ficient to ensure concerned participation of control room personnel in the review aspects of the TCR process. Specifically, that control room personnel recognize that their signature on the TCR indicates they have reviewed the TCR for additional operational input (TS and/
nr FSAR considerations), is a statement that the consequences of the job are known and is authorization to conduct the wor This item is close d. (Closed) Open Item 50-29/88-01-01: Review licensee actions to strengthen operations management awareness of the appropriate use of special orders. The inspector reviewed the licensee's use of special order No. 88-08 to blow down the main steam line pressure sensing lines in lieu of an approved procedure. The licensee considered there was an urgency to address the problem of cold weather treezing of the main steam line pressure sensing lines to prevent damage to
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the sensing lines and/or switches. Additionally, it was necessary to maintain the sensing lines clear for feedwater control. The licensee considers the decision to take immediate steps to correct the freez-ing problem was done with prior planning, discussion with appropriate department supervision and with necessary precautions. The special order was written to ensure that temporary guidance was given until the procedure was reviewed and approved by POR l
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- 5 In the meantime, a new procedure, OP-2260, Main Steam Pressure Sens-ing Line Blowdown was . initiated to address the necessary valving
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required to complete the blowdown evolution 'and return the valves to their proper . operating configuration. The inspector's observations supports operations department management's claim that they have reviewed their practices and are ' properly . sensitized to 'the issue that special orders are not to be used in -lieu of approved proced-ures. The inspector also understands the licensee'.s sense of urgency
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to.take immediate steps to correct the condition and'that precautions were appropriately. taken to ensure proper performance of the jo Furthermore, in line with NRC concerns, the licensee is developing procedures for all preplanned operations so that special ' orders will not be used for'these purpose However, the inspector noted that although the special order to blow >
down the sensing lines was written on January 14, 1988, the procedure addressing the pressure sensing line blowdown (OP-2260) was not writ-ten 'and placed into routing until February 11, 1988 and was not sent to PORC until March 15, 1988. Although timeliness of issuance -of this procedure was not evident, the licensee is aware of the NRC con-cerns associated with this lack of timeliness, and in this case, the lack of timeliness did not result in an actual safety concer This item is 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 conditions for operations (LCOs), instrumentation, recorder >
traces, protective systems, control rod positions, containment tem-
perature and pressure, control room annunciators, radiation monitors, radiation monitoring, emergency power source . operability, control ,
room and shift supervisor log, tagout log and operating orders. Based upon a review of licensee activities in this area, the inspector noted the following:
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(1) During control room observations, the inspector observed that training of reactor operator (RO) trainees has oeen conducted on an on going basis. Supervision of the trainees appeared con-scientious with one-on-one oversight provided by the licensed reactor operators during activities at the main control boar ;
The trainees were also questioned on relevant subject material I on systems by the R0's while on duty in the control room. Train- ,
ing of new plant personnel has been noted to be good and one-on- i one supervision by experienced plant personnel was evident. The
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inspector identified no 10 CFR 55.9 concerns regarding the fail-
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ure to maintain proper oversight of the trainee This was
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. 6 (2) The inspector noted during review of special orders that some difference of opinion existed on the part of operators as to whether the fine gain adjust potentiometer on tne main control board should be adjusted to actual percent of power or to 100%
power. The fine gain adjust potentiometer is used by the oper-ator to . adjust the power range. meter to agree with the calcu-lated primary plant thermal power.. This calibration is done once each shift. The operators were instructed that, at power levels greater than or equal to 90% of maximum allowable power, ,
the calibration levels are adjusted equal to actual percent -
powe At power levels less than 90% of maximum allowable power, the calibration levels are adjusted equal to 90% or as high as attainable but not less than actual percent power. The inspector also reviewed the use of a special order as deline-ated in procedure Ap-2006, Rev 6, Special Orders, and found the use of a special order appropriate in this cas '
(3) During the emergency load reduction on March 16, 1988 due to the trip of the No. 1 feedwater heater drain pump, which is reviewed in section 7f of this report, control rod group C was inserted to 72 inches to reduce main coolant temperature in accordance with procedure OP-3003, Rev. 12,. Emergency Controlled Plant Load Reduction. After attaining maximum allowable power, control rod .
group C is subject to an 80 inch rod insertion limit, If at any time af ter attaining maximum allowable power, control rod group ;
C is inserted below 80 inches, group C must be restored to above :
80 inches within two hours and the plant must be held at or below a calculated reduced power level for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with control rod group C above 80 inches before returning to maximum allowable power leve The limits on power level and control rod position following control rod insertion prevent exceeding the maximum allowable linear heat generation rate limits within the first few hours following return to power after the insertion. The 24-hour hold allows sufficient time for the initial Xenon distribution to accommodate itself to the new power distributio The restric-tion on control rod location assures that the return to allow-able fraction of full power will not cause additional redistri-bution due to rod motio Based on discussions with the licensee and review of applicable Technical Specifications (TS) and licensee procedure AP-7104, Rev. 69, Core Operational Limits, the inspector determined tha this reduced power level was defined to be 88% of rated power at this time in core life with control rod group C between 80 and 90 inches. The reduced power level decreases over core lif The licensee maintained the plant at or below 88% of rated power for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, then returned the plant to full power operatio The inspector determined that the reactor operations, including adherence to limits on power level and control rod position were
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acceptable, and had no further questions.
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. 7 (4) While the primary plant was being held in hot standby after the plant trip . on March 22, -1988 and after condenser vacuum was broken, the licensee commenced venting secondary side steam to -
the atmosphere via the emergency atmospheric steam dump (EASD)
system in lieu of the atmospheric steam dump valve, MS-TV-41 The atmospheric steam dump valve is used to maintain main cool-ant system temperature when the main condenser is not available or the non-return valves are closed; it can be lined up to vent steam via a common header to the secondary vent stack from any or all steam generators through vent valves upstream of the non-return valves. There are four emergency atmospheric steam dump valves; these ensure an adequate flow path for heat removal up-stream of the non-return valve While maintaining hot standby, the licensee used the emergency atmospheric dumps in lieu of the atmospheric steam dump valve, MS-TV-411 to vent secondary side steam to the atmosphere. This decision was based on observed moisture dripping _from insulation on the line downsteam of MS-TV-411. Subsequent to using the EASD, the insulation was removed and investigation revealed no problem with the lin The inspector questioned the use of the EASDs in Moce Pro-cedure OP-2105, Rev. 31, Plant Cooldown from Hot Standby permits the main coolant system to be cooled down utilizing the emerg-ency atmospheric dumps or MS-TV-411 if the main condenser is not available for a heat sink. However, licensee procedures did not specifically address use of the EASDs while maintaining Mode 3 (hot standby) conditions. The inspector questioned if any plant <
or equipment concerns existed with respect to maintaining plant t conditions using the EASDs continually in Mode Licensee onsite management reviewed the concern and performed an engineering evaluation demonstrating that the design intent of the EASDs was that they could be used in lieu of MS-TV-41 This evaluation determined that the EASD system was specifically designed for venting steam to atmosphere for main coolant system temperature contro They provide the same function as MS-TV-411; however, it provides increased capacity to vent ,
enough steam following a reactor trip, where one or more NRV's i had closed, to prevent challenging the main steam safety valve '
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The licensee pointed out that there existed procedural control of cooldown using the EASDs. However, the concern was that these controls were not in place for maintaining Mode 3 condi-tions. The inspector discussed these concerns with the Assist-ant Plant Superintendent about the need for the licensee to develop appropriate proceduras for all planned operation The
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e 8 Assistant Plan't Superintendent acknowledged the inspector's concerns and comment In response to inspector concerns, a procedure change notice to 0P-2109, Rev. _9, . Routine Shutdown Operation was issued 'to allow maintaining steam generator , tem-perature and pressure by use of the condenser _ steam dump,_
atmospheric steam dump or the EASD system. The inspector con-sidered that the licensee actions. taken were responsive to the NRJ inspector concerns and had no further questions on this issu ~
(5) Following the reactor scram on March 22, 1988 and while the plant was being maintained in hot standby with all control rods inserted into the core, control room personnel noted that the light emitting diodes (LED's) on the primary control rod posi-tion indication panel on the main control board were slightly illuminated. Normally, these LED's are lit in sequence when the control rod passes up through the control rod drive mechanism coil stack, indicating the position of the control rod with respect to the cor A two volt output from the secondary winding of the differential transformers is sufficient to illuminate the LED The licensee was concerned with this slight' illumination of the LEDs that was observed with the control rods fully inserted in the core. Concern was expressed that, as the control rods were withdrawn from the coce, it may have been difficult to discern actual rod position as required by the TS for Modes 1 and The TS requires all control rod primary and secondary position indicator channels to be operable and capable of determining control rod positions within 13 inche The licensee performed troubleshooting of the primary rod position indicator system to determine the cause of the percep-tible illumination of the LED. This troubleshooting included disconnecting the position indication (PI) cable from the No. 8 control rod drive mechanism (CRDM), connecting this cable to a spare coil stack and passing a pipe through the coil stac When the PI cable was removed from the CRDM, the LED for that control rod became completely dark. However, when the PI cable was attached to the spare coil stack, the LED became slightly illuminated as before. As the pipe was passed through the coil stack, the appropriate LEDs became brighter, distinguishing the position of the pipe. Additional troubleshooting was also per-formed; no problems were noted. The licensee considered that
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there was an induced voltage in the position indication cables, l that was causing the LED to be slightly illuminated and that '
once the control rods were actually withdrawn from the core, the induced effects would be discernible from the position signal.
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Prior to commencing withdrawal of control rods for the critical approach, procedure OP-2103, Reactor Startup~ and - Shutdown, a control rod motion and/or rod drop check is performed by with-drawing the-rod groups to three inches, then each group is with-
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drawn separately up to nine inches, then re-inserted to six inches. When all rod groups are finally at six inches, the manual scram button is depressed to fully insert all control rods. Operability of the control rod primary position indicator channels is required only in Modes 1 and 2. Guidance. was pro-vided to the operators by the Plant Operations Manager that if the operator could not determine control rod group "A" or "C" position within 3 inches, rod withdrawal should . be stopped while awaiting for further guidance from plant managemen Additionally, special order 88-31 was issued to the operators on March 23, 1988 to "hold" at step 4(f) of procedure OP-2103 when all rods were at six inches; this is just before the manual ,
scram described above. Also, to call the Plant Operations ;
Manager and Assistant Plant Superintendent at the beginning of
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OP-2103 so that PORC members would be present to witness rod light indication and determine if startup could continue or stop and conduct a control rod primary position indication light investigation. If the decision by the PORC members was to go ahead with startup, the Plant Operations Manager would give the operators the word to proceed. Prior .to performing rod group withdrawal per OP-2103 and performing the control rod motion !
test, procedure OP-4222, Reactor Rod Control System Precritical i Check was performed on control rod No. 8 to verify that the pri- ,
mary position indicating system cable was properly re-connecte l The PORC members were present to ob;erve the withdrawal of con-trol rod No. 8 to nine inches and ensure that the position of the control rod was evident to within 13 inches. The appropri-ate LEDs became considerably brighte To confirm operability of the primary position indication chan-i nels, the Assistant Plant Superintendent, the Plant Operations
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Manager and the inspector observed the performance of the con-trol rod motion check performed in accordance with OP-2103. The system was determined operable and rod withdrawal for critical-ity was initiated; no problems were encountered. The licensee j has stated that a service request will be issued to Yankee Nuclear Services Division (YNSD) to perform an engineering review of current system operatio l l
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. 10 Licensee concern and caution with respect to this problem was evident and its approach was conservative, as evidenced by.1)
the I and C department's troubleshooting of the primary position indicating system to determine the cause, 2) PORC members present to _ ensure operability of the system prior to reactor startup, 3) discussions held with the inspectors by-the licensee and 4) special orders to the operators to be conscious of con-cerns present with respect to operability of the centrol; rod position indication syste The inspector ' considered the responsiveness to this problem reflected a licensee strength and had no further question (6) Review of licensee procedures for reactor startup and .TS requirements and discussions with licensee personnel revealed ambiguities in the defining of the shutdown rod groups and the controlling rod groups. The Final Safety Analysis Report (FSAR)
states that there are three shutdown groups and one regulating group and that during power operation, the shutdown groups are essentially fully withdrawn while the position of the regulating group is adjusted to meet shutdown, reactivity and power distri-bution requirements. Review of licensee procedures and prac-
tices demonstrate compliance with these condition ,
However, review of the technical specification reveals an ambiguity in the definition and treatment of rod group A. TS 4.1.3.4 defines the regulating groups as A and C. TS 3.1. states that the control groups (written plural) shall be limited in physical insertion as shown on the rod insertion limit (RIL)
curve; however, the RIL curve is shown only for control rod group C position. The inspector also reviewed historical refer-ences with respect to whether rod group A is considered a shut-down group or a regulating group with inconclusive results. The RIL curve was changed in Amendment 77 (approximately 1982) to reflect an insertion limit only on rod group C. Licensee action is warranted to consider changing the TS to ensure consistency with the FSAR, licensee procedures and existing practices and to
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l eliminate the ambiguities that currently exist in the TS with I respect to rod group l l
No violations were identified during resident inspector ~ daily inspection b. System Alignment Inspection Operating confirmation was made of selected piping system train Accessible 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 i system performance was assessed. The following systems were checked during plant tours and control room panel status observations:
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Steam. driven emergency feedwater pum Spent' fuel cooling system
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Low pressure and high pressure. injection systems No violations were identified during system alignment inspections.
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c. Biweekly and-Other Inspections (1) General Facility Observation During plant tours, the inspector observed shift turnovers, compared boric acid tank sample analyses and tank levels to Technical Specifications requirements, and reviewed the use of radiation work permits and. radiation protection procedu re s ~.
Area radiation levels and air monitor use and operational status were reviewed. Verification of tagouts indicated the action was ;
properly conducte No violations were identified during resident inspector plant tour l (2) Fire Protection and Housekeeping On February 25, 1988 while observing a surveillance in progress, the inspector noted that the area under the safety injection
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(SI) tank had miscellaneous material and debris strewn in the -
enclosed area. The area under the SI tank is a locked heated ,
enclosur Items included a box . of light bulbs, electrical '
cable laying on the ground, numerous small pieces of wood and gloves scattered on the ground under the tank. The inspector.
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notes that this is a departure from the licensee's' strong com- ,
mitment to proper housekeeping conditions and practices. This matter was brought to the licensee's attention and prompt cor-rective action was taken to correct the condition. The inspec-tor had no further concerns relative to this ite With the exception of the above item, the licensee's performance in this area continued to be viewed as a licensee strengt The inspector had no further questions in this are No violations were identifie !
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.. 12 (3) Observations of Physical Security Selected aspects of plant security were reviewed during. regular and backshift' hours to verify that controls were in~ accordance witn. the security plan and approved procedure Based upon a review of licensee activities in this area, the inspector noted the following:
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During routine rJviews of access control activities the inspector has noted improvement in the professionalism and attention to detail exhibited by security officer Secur-ity equipment installed as part of access control features was observed to be generally available and operating properl The March 14, 1988 status listing of the security program improvement initiative issued by the manager of administra-tive - services was reviewed by the inspector. .No unaccept-able conditions were identifie The inspector reviewed security recordable event 88-074, which involved a loss of the normal alternating current (AC) power supply (due to a breaker trip) to the security ;
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system on March 21, 1988. The inspector noted that the licensee promptly and properly evaluated the event for re- '
portability in accordance with procedure AP-0009, Rev. 6, Reporting of Safeguards Events. Prompt and adequate com-
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pensatory measures were implemented. On March 30, 1988, the normal power supply was lost twice again due to breaker tri The inspector was concerned that the repetitive loss of normal a-c power to the security system due to the repeated tripping of the breaker was causing unnecessary challenges ,
to the backup emergency power supply (diesel generator). I Corrective actions on the part of the licensee to determine l the root cause and timely resolution of the problem follow- !
ing the first trip had not been evident. On March 31, 1988 l af ter the normal power supply was lost twice in the same i day, troubleshooting on the breaker was to be performed to assess and test the breake However, no- replacement breaker was immediately availabl Also, the security organization following the initial event did not ensure j
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inspector noted that this appeared .to be a departure from the positive trend noticed with respect to the . licensee providing a proper level of management oversight to ensure that timely maintenance is performed on security equipmen No -violations were identified during observations of physical security.
2 Backshift Inspection The inspector conducted backshift, weekend or holiday inspections on February 25, and March 9, 10, 14, 22, 23, 24, 26 and 27. Operators and shift supervisors were attentive and responded appropriately to annunciators and - plant condition No violations were identified t during backshift inspectio . . Rad _iological Control s Radiological controls were observed on a routine basis during the report-ing period. Standard industry radiological work practices &nd conformance
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to radiological control procedures and 10 CFR Part 20 requirements were observed. Independent surveys of radiological boundaries and random sur-
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veys of non-radiological areas throughout the facility were taken by the i inspecto j
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Inspection report 50-29/88-01 discussed inspector concerns dealing with
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observations of licensee personnel taking primary samples, in that good radiological work practices were not always evident. Due to the inspector
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concerns, the licensee has responded by using the newly instituted work observation program, which is described in section 15 of this report, to j assess the area of radiological controls as it applies to various jobs and i department Specifically, during the week of March 7, 1988 licensee l
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observations of personnel collecting the daily primary coolant samples l pointed out similar concerns, and also provided constructive, positive- '
methods to improve radiological work practices during this job. Recommen-dations included methods to eliminate the need for personnel to reach across a contamination boundary and storage of equipment used in sampling !
closer to sample points to facilitate access to supplies during the 4 sampling proces l I
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The inspector noted that these observations of work activities.in progress appear to be a positive approach to improve radiological work practices as they apply to all types of jobs in the plant. The licensee noted that the use of the work observation program is ideal te strengthen radiological work practices. The licensee responded in a thorough and timely manner to inspector concerns in this area, and the inspector had no further question No violations or radiation safety concerns were identified during radio-logical controls observation . Events Requiring Telephone Notification to the NRC The circumstances surrounding the following events, which required NRC ,
notification via the dedicated ENS-line, were reviewed. A summary of the inspector's review findings follows or is documented elsewhere as noted *
below:
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At 3:28 on March 8, 1988, the NRC was notified in accordance ;
with 10 CFR 50.72(b)(1)(v) that a major loss of emergency communica-tions capability had occurred at 3:15 p.m. This condition resulted from the discovery that the Nuclear Alert System (NAS) was inoper-able. When the NAS was found to be inoperable as a result of daily i surveillance testing, the licensee arranged for system troubleshoot-ing. The system was operable at 3:25 p.m. the same dat Inspector concerns involving licensee oversight of this system and determinations of reportability in accordance with 10 CFR 50.72(b)
(1)(v) were addresad in inspection reports 50-29/87-16 and 50-29/
88-06. Eariier in the day, the Plant Operations Manager issued special order No. 88-21, which made the plant operators aware of the ,
recent revision 7 of Op-Memo 2U-4, Nuclear Alert Telephone. This Op-Memo provided the necessary guidance to licensee personnel as to the conditions of NA5 inoperability that would constitute a signifi- <
cant loss of offsite notification capability and was viewed by the l inspector as responsive to NRC concerns in this are The inspector i had no further questions on this ite i
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At 7:10 on March 14, 1988, the NRC was notified in accordance
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with 10 CFR 50.72(b)(2)(iii)(0) that an inadequacy existed in the refueling outage surveillance procedure used to load test the three emergency diesel generators. Due to the inadequacy of the procedure, the licensee was unable to demonstrate documented evidence of compli-ance with either the TS requirement or the procedure's acceptance criteri This event is discussed further in Section 7e of this repor i l
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At 1:41 a.m. on March 22, 1988 the NRC was notified in accordance with 10 CFR 50.72(b)(2)(11) that an automatic reactor scram had occurred at 12:42 a.m. as a result of loss of power to nuclear instrumentation cabinet A. This event is discussed in Section 79 of this repor At 1:20 a.m. on March 23, 1988, the NRC was notified in accordance with 10 CFR 50.72(b)(1)(v) that the primary vent stack (PVS) sample lines were filled with water, resulting in the inoperability of the high range PVS accident monitor. This event is discussed in section 7h of this repor At 6:03 on March 26, 1988, the NRC was notified in accordance with 10 CFR 50.72(b)(2)(ii) that an automatic reactor scram had occurred at 5:29 a.m. as a result of low steam generator water leve This event is discussed further in section 7j of tFis repor The inspector reviewed the licensee's procedure OP Memo 2A-I, which used to make the ENS notification to the NRC. To provide clarifica-tion and for future historical reference, the licensee should record the applicable paragraph in 1G CFR 50.72 under which the notification was made on the notification for The inspector had no further concerns in this are . Plant Events Plant Lead Reduction due to Water Contamination of No. 3 Boiler Feed Pump (BFP) Oil Suppl'y At 2:00 a.m. on February 27, 1988, the licensee commenced a normal load reduction at 10% per hour to approxiniately 75% of rated power due to witer contamination of the No. 3 BFP oil supply. The licensee discovered the water contamination by a continually rising level in the oil sump of the No. 3 BFP; further investigation revealed emulsified oil. The water contamination of the oil supply was deter-mined to be due to the adjustment of the BFP oil slingers being too grea These oil slingers seal the pump bearings to prevent entry of water; normally the clearance is .025 inches, but was found to be .060 inches. The pump was taken off-line, the oil slingers re-adjusted to within specification, a new oil cooler installed and the bearing l gaskets and packing seals were replace The No. 3 BFP was returned to service at 6:45 p.m. on February 27, 1988 and the plant returned to full power operation on February 28, 1988, i
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. 16 As a result of reviewing special order 88-18 the inspector learned that the increase in oil reservoir level was not reported to mainten-ance in a timely manner. Therefore, the licensee instituted the following changes in their method of recording this level: (1) on the auxiliary operator log sheet, the actual level is now recorded, not just greater than 3/4 (full) as had previously been done, (2) any change in level is to be reported to the shift supervisor who will take immediate action and (3) action is currently being taken to issue a work request to repaint the gauge face. to whole numbers and <
the licensee is researching a mechanical reference device for the leve No inadequacies were identified by the inspecto b. Plant load Reduction due to No.1 Feedwater Heater Orain Pump Packing Leakage '
At 8:34 a.m. on March 3, 1988, a controlled load reduction was initiated to remove the No. 1 feedwater heater drain pump from ser-vice. The No. I heater drain pump was discovered to have excessive gland leakage. The pump was removed from service, and ' the motor, stuffing box and packing sleeve were removed. The stuffing box bush-ing was replaced, a new packing sleeve was installed and the stuffing box and motor were re-installed. The pump was re packed using eight rings of 1/2 inch Chesterton Style 370 packing. The inspector noted that the licensee has experienced numerous similar problems with the packing on the heater drain pumps. On September 18, 1987 an emerg-ency load reduction to 73% of rated power was initiated by the plant operators in response to a packing failure on the No. I feedwater heater drain pump. On September 28, 1987 a planned load reduction
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was initiated to 73% of rated power to repair a packing leak on the No. I feedwater neater drain pump (see inspection report 50-29/87-11 for details of these two events). On October 16, 1987 the packing on the No. I heater drain pump again failed to control leakage. A fail-ure analysis done at that time (File No./I.D. No. 0-12/FA 87-6) noted the cause to be a combination of sleeve wear and system changes. The heater drain pump was repacked and the packing adjusted to control leakage on October 17, 1987. Additional corrective action taken was to order new shaf t sleeves, a
The failure analysis recommended changing the shaft sleeve at the next outage to a new type of packing as recommended by the seal pack-ing representative. The old style of packing was a lead packing ring staggered with braided packings. As stated above the licensee has had previous problems with this packing. The licensee considers the previous problems may be due to the system cycling of the heater drain pump On March 3, 1988 obvious leakage was noted with the
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. 17 lead packing coming out the packing giard. The packing sleeve. had obvio'Js wear and grooves were noted on it. The pump was repacked with the Chesterton Style 370 packing rings. The Chesterton Style 370 is a new style of packing, manufactured from high quality carbon yarn, of interbraid construction and is considered to dissipate heat well. Additionally, the licensee has ordered a new failure analysis of the latest packing leakag The inspector concluded that the operating organization was providing a proper level of concern and oversight for the recurring problems with the feedwater heater drain r'
pump No inadequacies were identifie c. Load Reduction for Condenser Tube Leak Check Condenser water box tube cleaning and leak test was performed on February 20-22, 1988 (this item is covered in inspection report 50-29/88-01, Section 7). Only cne main condenser tube required plugging at that time due to several scrapers becoming lodged inside the tube. After condenser tube cleaning, leak checks were performed satisfactorily and the plant returned to full power. With the plant at full power the licensee noted during chemistry sampling of the ,
secondary side that condenser tube leakage might be occurring. Con- ,
sequently on March 12, 1988 the licensee commenced a planned load .
, reduction to approximately 48% of rated power in order to perform another leak check of the main condenser tubes. A total of five new leaks were found; two in the east water bex and three in the west water bo i Discussions with the licensee indicated that the development of addi-tional leaking tubes after condenser tube cleaning and leak test commonly occurs due to the mechanical shock incurred to the tubes by the strain produced as the scrapers are hydraulically propelled
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through the tube Forty-five minutes into the load reduction the licensen noted that the load decrease was not consistent with past experience. Investi-gation revealed the No. 2 and No. 3 control valves (CV) were closing
' simultaneously on the same oil pressure, approximately 40 psi. The ,
licensee compensated by slowly closing the No. 3 CV with the test device while slowly opening the No. 2 CV via the control switch from the control room. At 2:12 a.m. the No. 3 CV was locked closed with the test device and the load held constant by opening No. 2 CV; load decrease then was continued. At 11:15 p.m. while returning to full
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power operation, at 36 psi governor oil pressure, the No. 3 CV came off its closed seat and increased load approximately 25 MWe on the generator for 20 seconds. The licensee reduced governor oil pressure -
and returned generator load to pre-transient condition. problems
with the turbine control valves were also addressed in inspection report 50-29/88-01.
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As a result of the transient caused by the generator increasing load by approximately 25 MWe for 20 seconds, the. inspector held discuss-ions with the licensee and reviewed several main coolant recorder tracings for the - time period' involved. The short duration of the-transient did not affect plant conditions to any exten The increase in load caused-an approximately eight inch drop. in pressur-izer level, indicating less than 1.5 degree F change in main coolant system temperature ;with main coolant system pressure showing normal -
plant respons s During the load reduction for condenser tubeEleak check, maintenance was also performed on the No.1 feedwater heater drain pump and the No. 3 boiler feed pum Subsequently, during the plant shutdown on March 22-23, 1988, a Westinghouse representative was on-site to assist the licensee i '
. performing maintenance on the turbine control valves. The licensee adjusted components on the servo' motors in response to previous prob- '
lems. Two servo motors are on order and will be used as replacements during the next refueling outage. Following the control valve main- ,
tenance, no abnormal equipment performance has recurre The inspector had no further questions on this even Plant Worker Transported to Offsite Medical Facility ,
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On March 10, 1988, a plant office worker became ill, which resulted '
in the transport of the worker to an area hospital. On-site medical '
perscnnel recommended that an ambulance be called, but that activa- i tion of the declaration of a medical emergency was unwarranted. The l shift supervisor reviewed procedure OP-3305, Rev. 7, On-site Medical '
Emergencies and determined that the event was not a medical emerg- :
ency. He also demonstrated to the inspector his awareness that this ;
event did not fall within any of the Emergency Action Levels con- !
tained in procedure OP-3000, Rev. 5, Classification of Emergencie !
Based upen the condition of the ill worker, it was unnecessary for - ]
the ambulance to enter the plant protected area. Plant personnel l response to this event was well coordinated and timel :
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As a result of reviewing this event the inspector noted that proced- I ure OP-3305 requires the shif t supervisor to review applicable pro- I cedures for declaring an Unusual Event. In addition, it provides the following guidance: 1) for tne purposes of a contaminated individual without bodily injury, transport to a hospital or off-site medical facility for medical attention shall not require an Unusual Event i declaration; and 2) if the injured individual is contaminated and requires transport to an off-site medical facility, then an Unusual Event is in progress. The first item was added to the procedure to preclude the declaration of an Unusual Event as a result of an indi-vidual being transported to an off-site medical facility for the sole
. purpose of the medical removal of a hot particle located on the skin ,
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When the inspector questioned plant operators about how they would classify events dealing with illness, heart attacks, etc. which involved contaminated individuals, .a uniform approach was not note Inspector concerns that the existing guidance incorporated ambiguity into the procedure was discussed with licensee representatives and NRC:RI emergency preparedness management and specialist inspector Subsequently, procedure OP-3305 was revised by the licensee.. The inspector verified that the licensee's corrective "actions were timely and appropriat The inspector had no further questions on this event, Inadequate Surveillance of Emergency Diesel Generators t On March 14,.1988, the inspector was informed by the licensee that an ,
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inadequacy existed in the refueling outage surveillance procedure used to load test the three emergency diesel generators (EDG's). This load test verifies that the EDG is capable of (1) starting on a loss of a-c supply, (2) supplying emet gency bus loads and (3) rejecting a
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1arge load without trippin Technical Specification (T.S.)
4.8.1.1.2 d.4 requires the licensee at least once per 18 months dur- ,
irg shutdown to verify that each EDG operates for greater than or equal to 60 minutes while loaded to greater than or equal to 400 K During the review process of OP-4209, Rev. 17, Emergency Diesel-Generator Test during Refueling Intervals, the licensee discovered that the 18-month load test which was currently performed on the EDGs did not appear to meet (verbatim) the Technical Specification re-quirement. This procedure requires that each EDG be tested in accord-ance with T.S. 4.8.1.1.2.d.4 by verifying the diesel generator oper-ates for equal to or more than 60 minutes whi'e loaded to equal to or greater than 400 KW or 500 KVA. A note adds that the KVA rating can .
be used when the system power factor limits the KW laading to less than or equal to 400 KW (i.e., 500 KVA may be substituted for 400 KW if a sufficiently high power factor is not achievable). The actual procedure step parallels the EDG with the 480 volt bus and picks up equal to or grater than 400 KW (or 500 KVA) load. An additional note states that the governor adjust switch may be insufficient to load to greater than or equal to 400 KW; in this case increase the voltage regulator adjustment to attain greater than or equal to 500 KVA. The acceptance criteria is that the EDG operated 360 minutes while loaded to 1400 K Operations Memo #88-19 dated January 26, 1988 from the Operations Department Manager to the Assistant Plant Superintendent requested justification for testing the EDGs to 500 KVA as allowed by the pro-cedure instead of testing to 400KW as required by TS. Engineering evaluation (MSD memo 32/88 dated March 9,1988) determined that no decumentation had been found to justify accepting 500 KVA instead of
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. 20 400 KW during the 18-month test of EDG's. Additionally, the 500 KVA substitution does not test the EDG's ability to produce 400 KW of power; depending on the power factor 500 KVA could have an associated power of 0 to 500 K The above event constituted a violation of T.S. 4.8.1.1.2.d.4 in that the procedure, OP-4209 did not adequately reflect objective evidence that the TS requirement that the emergency diesel generators was verified to operate for 360 minutes while loaded to 2400 KW. The licensee's procedure did not document what the EDG was loaded to and therefore, it can not be demonstrated whether the diesel generators did or did not meet the TS requirement This item meets the cri-teria of NRC Enforcement Policy, 10 CFR 2, Appendix C, Section V. for a licensee identified item and a notice of violation will not be issued, in that: the item wa; identified by the licensee; it consti-tutes a severity level IV or V violation; it was reported to the NRC; it was not an item that the licensee could reasonably be expected to prevent by corrective action from a previous violation and the item will be corrected including measures to prevent recurrence within a reasonable length of time (50-29/88-05-01). The inspector will review the licensee's ::orrective actions as part of the NRC's review of the LER that is to be submitted as a result of this even The inspector had no further questions of the licensee on this event at this tim The licensee considers that the 500 KVA was derived from the EDG name plate rating, which reads 400 KW, 500 KVA, 80% power factor, 480 VAC, 600 amps. Furthermore, the 500 KVA substitution was apparently first used in October, 1979 when difficulty was encountered in obtaining 400 KW during the 18-month surveillance. Because the procedure did not require complete documentation of EDG performance data during the test, the licensee was unable to demonstrate compliance with either the TS requirement or the procedure's acceptance criteria. Prior to the procedural change in 1979, 405 to 415 KW was produced with almost unity power factor during the EDG load tes The licensee's immediate corrective action consisted of revising the weekly surveillance procedure (0P-4207, Rev. 24, Surveillance of the Station Power DC and AC Distribution Systems and the Emergency Diesel Generators) to load the EDGs to the TS limit of 400 KW for one hour period or, if this was not possible, to a value that met the worst case load profile for each generator. An engineering evalua-tion was conducted to determine the worst case load profile at steady state for each EDG. Results were based on 1985 data; for EDG No. 1 a 345 KW value was specified, fcr EDG No. 2 a 342 KW value was specif-ied and for EDG No. 3 a 360 KW value was specified. The load test l demonstrated that the EDG's were readily capable of attaining and maintaining the name plate rating of 400 KW,
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. 21 NRC concerns with respect to this matter involved the followin First, licensee plant management was first made aware of the possi-bility that the 18-month surveillance tests may not have been meeting (verbatim) TS requirements on January 26, 1988. The maintenance support depar tment's evaluation concluded that the substitution of 500 KVA for the EDG's 400 KW load test did not demonstrate the EDG's ability to produce 400 KW load test was dated March 9,1988. How-ever, the inspectors were not made aware of this discrepancy until March 14, 198 The inspectors discussed the problem with NRC regional management and with- the NRC:NRR project manager. All con-curred that the appropriate course of action was to accurately deter-mine the worst case load protile for each EDG and load test each EDG to 400 KW, or if not possible to attain the 400 KW, load test to at least the value determined for the worst case load profile to ensure the licensee could meet the plant design basis for the emergency core cooling syste Long term corrective actions by the licensee as specified in special order 88-27 include revising 0P-4209 and provide more meaningful data requirements. Also, the licensee is evaluating a TS change to make the surveillance requirements less restrictive, yet meet the design basis with some additional margin. The inspector had no further questions concerning these matter f. Emergency Load Reduction due to Trip of No.1 Feedwater Heater Drain Pump At 10:35 a.m. on March 16, 1988, a high vibration panalarm was received on the No. 2 feedwater heater drain pump (HDP). Investiga-tion revealed that the No.1 HDP had tripped; the pump was restarted but tripped again approximately 30 secondt late The licensee initiated an emergency load reduction to approximately 73% of rated power by driving the control rods in and reducing generator load to prevent tripping the plant on loss of feedwate The plant was stabilized at approximately 73*; of rated power. The licensee con-siders that work in an adjacent breaker cubicle for the No. 1 fire pump may have caused the No.1 HOP to trip; however, after trouble-shooting, no apparent cause for the trip was determined. The No. 1 heater drain pump was returned to service at 1:30 p.m. the same day, power level increase was commenced to the TS required reduced power level, and held at this reduced power level until March 17, 198 On March 17, 1988, with the plant stcble at the reduced power level, the licensee discovered a shaft sleeve packing leak on the No. 2 HD With the plant already at a reduced power level and stabilized while waiting to complete the 24-hour reduced power hold, plant load was reduced further to approximately 70% of rated power, the No. 2 HDP was removed from service to repair the packing leak and the p' .p was returned to service. After completion of the 24-hour hold on reduced power level, the licensee commenced returning the plant to full power
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. 22 Reactor Scram Due to Loss of Power to Nuclear Instrumentation Cabinet At approximately .12:42 a.m. on March 22, 1988, an automatic reactor scram occurred from full power due to loss of power to nuclear
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instrumentation (NI) cabinet A. The plant was stabilized in hot
- standby (Mode 3) and remained in hot standby until the next day when the NIs were returned to servic The licensee also performed various maintenance work during the plant shutdow A capacitor.within the regulating - transformer supply for NI cabinet failed, which resulted in the loss of some of the plant NI and the ,
de-energization of a scram amplifie Drawings available at the !
plant did not show the- size capacitor required for replacement; how-ever, the original, failed capacitor was removed and used as a guide to determine the proper replacement. The licensee contacted the ;
original manufacturer of the transformer and the manufacturer of the replacement capacitor to determine correct capacitor size, equiva-1ency of the replacement capacitor to the original capacitor and a ;
recommended burn-in time to dedicate the new capacitor for rafety-
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related use. Subsequently, the licensee obtained a replacement ;
capacitor and dedicated it for use in a safety-related system by -
performing a twelve-hour burn-in as recommended by the manufacturer of the replacement capacito '
On October 26, 1985, power was lost to NI cabinet A; at that time, the regulating transformer was replaced. Since the capacitors in the t
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transformers were original equipment in the plant, the licensee decided to replace the regulating transformer capacitors during the next refueling outage. In May-June 1987, the regulating transformer capacitors in NI cabinets A and B were replaced. During the last i refueling outage, the size of the capacitors used as replacements was !
determined by using the size of the existing capacitors removed from i the NI cabinet transformers. These capacitors were bought as com- !
mercial grade items; although not individually dedicated for use, '
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af ter the capacitors were replaced in the regulating transformers, a 100-hour burn-in was performed. The inspector noted that, although the issue of using commercial grade items in safety-related systems without dedicating the equipment has been an on going NRC concern at the plant, the licensee took appropriate measures during. repair of 1 the NI cabinet during this shutdown to determine the correct capaci-tor for use and to ensure that the component was dedicated for its I intended use.
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. 23 The loss of power to the NI cabinet resulted in the inoperability of
. one of the two source range channels. Although the technical spec - ,
ification only requires one operable source range channel in hot standby, as a precaution, the licensee attempted to establish a second source range monitoring channel located within the safe shut-down building. However, this channel was found to be inoperable due to a loose fuse; the channel was subsequently made operable. The licensee made an ENS call on this event at 1:41 a.m. on March 22, 198 The inspector reviewed the post-trip review and all systems- and equipment responded as expected. The inspector also observed that technical specification requirements for' Mode 3 operation were being met by performance of procedure OP-4212, Rev. 4, Main Coolant System
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Residual Heat Removal Availability Verification on a shift basi This procedure ensures there is sufficient main coolant system i residual (decay) heat removal capability availabl The inspector observed plant start-up and noted that appropriate pro- l a
cedures were being used and followed, appropriate caution was exer- i i
l cised by the control room operators during the critical approach and I that they were thoroughly knowledgeable and observant of plant conditions and operations, j
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On March 23, 1988 at 1:20 a.m., it was discovered that the primary !
3 vent stack (PVS) process radiation monitoring equipment, including !
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the high range monitor, was inoperable. The PVS is the exhaust path l for the ventilation systems from the primary auxiliary building, the i
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waste disposal building and the spent fuel pit building. The weam (
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generator blowdown tank also vents to the PV The PVS process j radiation monitoring system monitors the air flowing throu@ the PVS l for noble gas radioactivity, iodine radioactivity and particulate
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radioactivit The radiation monitors provide information which is ,
used to calculate the total release of radioactivity from the PV '
Four sample lines (two for iodine and two for noble gas) penetrate
, into the PVS with nozzles that point down into the flow stream; one of each line is in use. The iodine sample line goes to a fixed particulate and an iodine detector in serie The noble gas sample line goes to moving particulate and noble gas detectors which are in
series. These lines then join together and return to the PVS. A i
high range radiation monitor samples the return gas to the PVS. This high range monitor is an accident assessment instrument, used in an emergency to aid in assessing the off-site radiological hazards due ,
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Licensee investigation of anomalous control room indication revealed- .
water in the sample lines from the PVS up to the detector shield !
enclosure which encloses the above four detectors. Further investi-gation revealed that the heat tracing on the system piping had been ,
turaed off. All of the system piping is heat traced to prevent any '
condensation of moisture in the piping. Upon opening the particu-late iodine and noble gas detectors, water was also found inside these detectors. Based on the flow configuration and the water in ,
the sample lines and detectors the licensee made the assumption that
. there was no air in the line up to the high range radiation monito l The licensee declared the high range monitor inoperable, and due to the loss of emergency assessment capability, made a one-hour ENS call. The water in the system was determined to have been caused by the combination of ' increased blowdown of the steam generators (the blowdown tank vents to the PVS) while the plant was in Mode 3 and the sample line heat tracing being of i The water was drained from the system, the heat tracing was re- l
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energized, air flow re-established and within one hour the high range '
monitor was operable. A functional test of the system was performed later in the day with satisfactory results and the entire system was
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considered to be functiona Investigation into the cause of the heat tracing being de energized revealed that when the reactor had tripped on March 22, 1988, the
- power to the temperature indicator controller was interrupted. When i
power was restored to the system and controllers, an amber alarm light on the controller began flashing indicating the limit relay had i de-actuated, It continues to flash when the controller is re-
energized until temperature rises above the . limit setpoint and the limit reset button is depressed. When the flashing amber light was noticed, the controller was turned off by plant personnel not
- familiar with its operations. The licensee plans to issue a Plant Information Report to discuss this event, which will describe its
- corrective actions, i
l Radiological Event: Removal of Radiation Area Barrier Posting ;
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At approximately 10:00 a.m. on March 24, 1988 the day shift radiation protection (RP) technician discovered that the swinging gate and its I attached Radiation Area / Radioactive Material postings were missing from the entrace of the primary chemistry sample cubicle. Thia cub-
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icle is located in the upper primary auxiliary building (PAB). With-in ten minutes actions were completed that consisted of: (1) per-forming a survey of the area; (2) properly posting the area; and (3)
notifying RP department management about the event. An intensive ;
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. 25 investigation and identification of further immediate corrective actions were initiated by the licensee. The inspector was informed of the event and licensee actions in a timely manner and later on March 24, 1988, the inspector discussed the condition with a cognizant NRC:RI Division of Radiation Safety and Safeguards specialist inspecto The following additional actions were implemented by the licensee on March 24, 198 An investigation was conducted by the security and RP department managers, which included: (1) review of access and alarm print-outs to identify personnel entry into the PAB and protected area alarms during the ti::.e of interest; (2) inspections of the affected and surrounding areas by RP, operations, and security personnel; (3) review of dose records to determine if any unusual or unexpected radiation exposure had occurred; and (4)
detailed interviews with personnel who had access to the PAB during the time of interes Increased surveillance of postings in the radiation control area was instituted to assess the nature and scope of the incident, and monitor the situation for potential recurrence. This action resulted in increasing the posting inspection by RP shift tech-nicians to include all zones, and initiating a Monday through Friday daily supervisory inspection utilizing a specially developed checklis The missing gate and postings was located within its area and replaced on March 25, 1988. Hinge bolts have been peened over i.o preclude unauthorized removal of the attaching nut As a result of the above investigation, the licensee concluded that the event occurred some time between 10:00 p.m. on March 23, 1988 and 3:45 a.m. on March 24, 1988. The inspector noted that the licensee's conduct of its investigation and implementation of timely corrective was both aggressive and thorough. However, one additional item involving personnel performance was a significant departure from the excellent manner in which the licensee approached this event. This involved the fact that at 3:45 a.m. on March 24, 1988 a chemistry ,
technician notified the RP control plant that the gate / posting was '
missing, but the RP shift technician assumed it had been removed intenticnally on the previous day and neither investigated nor fol- ;
lowed up on the report. The initiating incident and failure to fol-low up on the report of the missing barrier and posting were the subjects of Radiolog cal Occurrence Reports issued on March 24, 1988 by the licensee. The inspector verified that the licensee identified and implemented timely and appropriate corrective actions for the RP technician's failure to properly investigate the reported conditio l l
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In addition, the Plant Superintendent directed that the RP Manager will document the licensee's investigation, corrective actions, and
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i analysis' in Plant' Information Report No. 88-3. On March 30, 1988, l the inspector attended a plant safety meeting. At this meeting a session was presented to plant personnel on posting requirements, the purpose of these postings, and what is . expected of plant personnel ,
with' respect . to 'the postings. This event and its consequences were ;
discussed by the Plant Superintendent, . Technical Director, and RP c Manager so as to re enforce the seriousness of the potential conse- i quences of the identified even ;
This event constitutes a violation of 10 CFR 19.12 and 10 CFR 20.203 t (b) and (e), the former requirement involving instructions to workers and the latter requirement involving caution signs, labels,' signal and controls. However, this item meets the criteria of NRC Enforce- .
mant Policy, 10 CFR 2, Appendix C, Section V.A. and a Notice of Vio-
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i lation will not be issued, in that: the item was identified by the .;
licensee; it constitutes a severity level IV or V violation; it was ;
' not an item that the licensee could reasonsbly be expected to prevent t by corrective action from a previous ' violation and the item will be 6
!, corrected including measures to prevent recurrence within a reason- *
1 able length of time (50-29/88-05-02). The inspector will review PIR
- No. 88-3 during a subsequent inspection.
' Reactor Scram on Low Steam Generator (SG) Levels i (
On March 26, 1988, the plant was at 85% of rated power, and in the ;
process of increasing power -to full load, when at 5:29 a.m. an auto- ;
matic reactor scram occurred as a result of low levels in the Nos. 2
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and 4 SGs. This condition was caused by the improper functioning of a power supply in the feedwater control system that caused erratic operation of the feedwater control valves for these two SG Al-i though the secondary side control .oom operator responded rapidly to the low SG level alarm, he was unable to take remote manual control of level for these SGs because of the power supply failur The automatic reactor scram occurred approximately 30 seconds following .
the onset of the erratic operation. The plant responded as expected
! to the trip. Timely notifications were made to the NRC headquarters duty of ficer and inspecto The inspector responded to the plant, i reviewed the Yankee Rowe Post-Trip Report developed in accordance '
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i with procedure AP-2003, determined that the plant was being main-tained in a stable hot standby Mode 3 status and reviewed the licen- ;
see investigation and corrective action Review of licensee cor-q rective action in response to the power supply failure in the feed- l l water control system is contained in Section 8 of this repor '
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A reactor startup commenced on March 26, 1988 with the reactor crit-ical at 10:25 p.m. The generator was phased to the grid at 2:20 on March 27, 1988. Plant operators noted during the reactor startup on March 24, 1987 from the prior trip and during the recovery from 1 this trip, that valves on the No. 3 feedwater line were leaking b :
Maintenance requests were issued to identify the equipment conditions and the operations department issued Special Order No. 88-34 . and revised appropriate procedures to provide increased. awareness and guidance necessary to operate the plant with this conditio As a result of observing the startup on March 24, 1988 and the licensee's implemented corrective measures to compensate for the condition, the inspector identified no significant concerns associated with the planned manner of operation Strong licensed operator performance ;
was noted during difficult evaluations of the plant stectup, a
As a result of reviewing the actions of the control room operators in responding to the reactor trip and maintaining the plant in mode ,
3 operations, the following inspector concerns were identified: '
(1) The sequence of events recorder showed 'that the operator's actions to reaffirm the reactor scram and turbine trip did not occur until approximately five minutes after the reactor trip
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occurre ,
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(2) Inconsistencies existed between control room indications for 4 condensate pump discharge pressure and boiler feed pump suction ,
i pressure. Operator awareness and corrective actions occurred ;
following inspector identification of_the condition.
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(3) Procedure OP-4212, Re v .. 4, Main Coolant System Residual Heat !
Removal Availability Verification, requires once per eight hours a verification that each SG water level is above the top of the tube bundle. Procedural guidance specifies that level is either ;
greater than minus fifteen inches on the narrow range level !
- instrument or greater than twenty-two feet on the wide range l level instrument, and references T.S. surveillance requirement 4.4.1.1.2.3.c. This T.S. surveillance requirement specifies that the SG water level is above the top of the tube bundle for
, the main coolant loop required to be in operation. In Mode 3,
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T.S. 3.4.1.1.2.b requi res at least one main coolant loop in operation. On March 26, 1988 the inspector noted that all four main coolant loops were in operation; however, SG No. 4 was at a i level of twenty feet and the other SGs were above twenty-two i feet. The inspector questioned the control room operators, about 2 the plant conditions versus the procedure OP-4212 required
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verifications and its acceptance criteria that stipulates that ;
the required coolant loops are operable and/or-in -operation as -
required. There appeared to be confusion as to exactly what the _
Mode 3 operational limitations are .for the SGs'and their impact on main coelant loop ope atio This in large measure is ,
attributable to ambiguity. in .4.1.1.2 and the. overly restrictive verification required by OP-421 The -inspector concluded that the first two items above are .sympto- r
- matic of -the need for control ' room personnel to exhibit a greater i level of attention to detail. A review of past records indicate that :
the first item is an isolated incident and is not reflective of the
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normally high level of performance attributable .to control room oper-i ators in their response to plant events. In addition, an appropriate level of concern was exhibited by the Assistant Plant Superintendent
and the Plant Operations Manager which resulted in the immediate
, development and issuance of Special Order No. 88-35 that was utilized 1 to bring the concern to the operators' attentio The last item indicates that a review of licensing and procedural requirements is a
warranted to ersure clarity in decay heat removal requirements in Mode 3. The inspector had no further questions of .the licensee on ,
this ite :
8. Maintenance Observations ,
The inspector observed and reviewed maintenance and problem investigation j activities 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 controls for worker protection, fire protection, retest requirements and reportability per Technical Specifications. The follow-ing activities were included:
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MR 87-1590, Repair defective lose fittings on fuel oil return line 2 on emergency diesel generator No. 2 l
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MR 88-335, Excessive drift on main steam line pressure switch 3 MS-PS-24 for channel 2
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MR 88-537, MS-PS-34 main steam line pressure switch setpoint drift
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MR 88-550, MS-PS-33 main steam line pressure switch preventive
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maintenance
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MR 88-551, MS-PS-32 main steam line pressure switch preventive maintenance
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MR 88-374, Excessive gland leakage on No. I heater drain pump
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MR 87-1728A, Excessive packing leakage on No. I heater drain pump
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MR 88-410, Safety injection building auxiliary fire detection panel -
l battery No I failed functional test ,
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MR 87-2016, No. 2 purification pump has high vibrat. ion
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MR 88-211, Inspect No. 2 purification pump due to high vibration l
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MR 88-487, Nuclear instrumentation cabinet A - loss of power to
entire cabinet
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MR 88-494, Reactor trip -breakers BK-1 and BV:-2 -
preventive maintenance
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MR 88-496, No. 3 main coolant stop valve (MC-MOV-310), packing leak
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MR 88-497, No. 1 main coolant stop valve (MC-MOV-326), packing leak
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MR 88-527, No. 2 feedwater control valve operating erratically
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MR 88-544, No. 2 feedwater controller erratic Based upon a review of licensee activities in this area the inspector 4 noted the following:
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The inspector reviewed the licensee's repair activities associated with MR's88-335, 88-537,88-550 and 88-551, which covered the cor- !
rective and preventive maintenance on main steam line pressure 3 switches. The inspector's review is documented in Section 9 of this report.
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Regarding MR 87-1728A, the inspector's review of heater drain pump problems is documented in Section 7.b of this report.
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The inspector's review of repair activities associated with MR 88-487 is documented in Section 7.g of this report.
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Regarding MRs88-496 and 88-497, the maintenance department corrected ,
identified stem leakage on main coolant stop valves in loops No l and 3 on March 23, 1988. Subsequently, the valves vere released by j
the control room operators to allow maintenance personnel to perform procedure OP-4517, Rev. 12, Surveillance of Motor Operated Valves.
' T.S. 3.4.1.1.2.a requires all loop stop valves to be open in Mode Since the valves were cycled for time testing, and therefore closed for a brief period of time, it is required to acknowledge and follow
the TS Action Statement that allows this condition for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
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. 30 The inspector noted that the control room operators were not aware of the TS requirement, and therefore did not enter their acknowledgement in the control room log. On March 25, 1988, the Assistant Operations Manager issued Special Order 88-33, which provided a cogent discuss-ion on the inspector-identified issue and was an appropriate level of corrective action since the special order is also sent to the train-ing department for incorporation in operator licensing training activitie The inspector considers this event to have had minimal safety significance and represented an isolated breakdown of the licensee's equipment release controls. The inspector had no further questions on this matte As a result of reviewing maintenance activities associated with MRs 87-2016 and 88-211, the inspector noted that the licensee's mainten-ance department and quality control group had self-identified issues involving failure to document retest activities prior to returning the equipment to service, and failure to insure the proper dispo-sitioning (i.e., dedication) of a commercial grade motor mounting bolt on the safety grade purification pum Both items are of a continuing concern to the NRC. However, the inspector acknowledged concerted licensee efforts to provide proper dispositioning of issues that are of concern to both the licensee and NR For the former concern, the inspector reviewed Special Order 88-25, dated March 14, 1988, which provides a memorandum to all operators that describes a newly instituted interim requirement. This require-ment specifies that prior to the return of safety-related equipment to the control of the operations department subsequent to the com-pletion of maintenance activities, which could include retest per-formcd by the maintenance department, a maintenance support depart-ment engineer and the cognizant maintenance department supervisor; or two maintenance supervisors, must review the MR and initial it before releasing the equipment to the operations department. This require- !
ment will stay in effect until the new post-maintenance testing pro-cedure being developed is issued for use. The licensee believes, and the inspector concurs, that the interim requirement will provide the proper level of assurance that equipment or components requiring QA are properly tested following the performance of repairs, and prior l to it being declared operable and returned to servic Nonconform- i ance report 88-3, was issued on February 1, 1988 to document the :
issue, provide for an appropriate disposition of the identified !
dificiency, and ensure the proper level of management revie i
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. 31 In response to the latter concern, and one that has been recurring and documented in recent Inspection Reports 50-29/88-01 and 50-29/
88-02, the Plant Maintenance Manager developed and conducted a train-ing session for the cognizant maintenance and QA personnel, on February 29, 1988, which described an interim measure that will be used unilaterally to dedicate commercial grade materials for use in safety-related application The inspector attended this training session, determined that the licensee's program to utilize plant pro-cedure AP-0212, Rev. 14, Control of Purchased Material Equipment and Services and QA procedure 0QA-IV-2, Plant Procurement Document Review for the dedication process was an appropriate interim response to the NRC concerns. In addition, throughout the remainder of the inspec-tion period the inspectors observed adherence to the licensee's described interim program. Since the licensee will be responding to a Notice of Violation due to concerns in this area identified in-Inspection Report 50-29/88-02, the NRC will review the issue in a subsequent routine inspection. Additionally, the inspector reviewed the March 1, 1988 evaluation conducted by a maintenance support department (MSD) engineer that the use of the commercial grade car-riage bolt on the purification pump motor does not represent a safety concern. Because of questions that plant personnel have as to the necessity to maintain the safety class designation of the purifica-tion pumps, the MSD supervisor initiated a service request to YN05 to resolve the issu The inspector had no further questions of the licensee on these matters at this tim The licensee's repair activities for the erratic feed water control system, as controlled by MR 88-544 were reviewed. Two items of con-cern were identified by the inspector es described below:
(1) The first item involved the mechanism by which the licensee repaired the failed power supply that had caused the erratic operation of feed water control for SGs No. 2 and 4. Because the licensee did not have available a replacement power supply, l they obtained a nearly equivalent replacement from a neighboring '
utility. Although this replacement was a quality grade unit, it did not have an automatic transfer capability that allowed the i two channels of the feedwater control system being supplied by j the power supply to continue to operate from a backup 125 volt ;
d.c. supply in the event that the normal 120 volt a.c. supply is i lost. The normal 120 volt a.c. supply is provided by the 120 i volt a.c. vital bus No. 2. The licensee used Temporary Change I Request (TCR) No. 88-99 to control the condition that the two i 125 volt d.c. leads needed to be lef t in a lif ted stat The i I
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I&C department in developing the TCR specified that the TCR will
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not affect an operable syste .
Their view was based upon the fact that the FSAR does not describe the system's feature of a backup power feed and within the constraints of their under- ,
standing of the system design they were performing a replace- >
ment-in-kind maintenance activit The inspector considered that the activity was in reality a . modification effor The proper method of conducting the maintenance activity should have resulted in the development of a safety evaluation, identifica-tion of impact on plant operation the modification would have, and the performance of a pre-implementation PORC review.
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Discussions with licensee representatives, as well as a review of the design change .that installed the current feedwater con- ,
trol system during the 1984 refueling outage, indicated that the automatic transfer feature of the power supply was a reliability enhancen en It is not in the licensing base of the plan 'Followin3 discussions with maintenance department and plant management representatives on this issue, who acknow', edged the inspectors comments and concerns, the lir.ensee issued on '
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March 28, 1988, Revision 1 to TCR 88-99. This revision provided a safety evaluation and documented the affect on plant operation
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by the use of the replacement power supply in the feedwater con-trol syste This revision was reviewed and approved by the POR In addition, the inspector noted active involvement of
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the YNSD cognizant engineer, who was knowledgeable on the -feed-I water control system design aspects, in the determination of !'
acceptability to use the replacement power supply. Following the review of the licensee's administrative procedures that con-
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trol maintenance and modification activities at the plant, the inspector was unable to locate clear guidance to plant personnel on treating repair activities that do not result in one-for-one component replacements as modification activit The licensee
- has informed the inspector that their efforts to review and revise their maintenance program will resolve this issue by clearly specifying policies and work practices associated with
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maintenance versus modification activit ;
a 1 (2) The second concern, which to some degree is related to the item
- ) above, deals with the licensee's failure to identify the necessity to revise procedure OP-3250, Rev. 12, Loss of a 120
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VAC Vital Bus. This activity should have resulted from the I' licensee's determination to not replace the power supply with an exact replacemen The aforementioned procedure provides instructions for recovering from the loss of a 120 volt vital bus, and specifies that: (1) the loss of vital bus No. 2 should not cause a reactor scram and (2) that the feedwater I i
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control system power supply for SGs No. 2 and 4 transfers to battery backu As a result of the licensee's repair activity the system will not respond as originally envisioned, which now includes the -increased possibility of a reactor trip which i dictates that it would be appropriate--to alert the control ~ room operators to those _necessary considerations and immediate oper-ator actions that should be followed as part of the event recover Upon the inspector's identification of this issue, the licensee was informed. Following' their review of the situa -
tion, an appropriate revision was issued to the procedur Special Order No. 88-36 was issued on March 28, 1988 to inform ,
the control room operators of the issue and attached the revised procadure which provided proper instructions and considerations necessary for respding to the even The inspector' reviewed the revised procedure and determined the licensee's corrective actions were fully responsive to the NRC concerns on this-matte !'
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The maintenance activities involving the performance of preventive maintenance on both reactor trip breakers (RTB's), were reviewed by
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the inspecto Although the shunt trip coils were functioning i properly, the licensee determined that it would be prudent to replace the existing shunt trip coils with new exact replacements. -The licensee was implementing a recommendation of the breaker manufac-turer, Westinghouse. The inspector noted that the maintenance -
department - utilized the March 22, 1988 plant trip to implement the
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Westinghouse recommendation and perform routine preventive mainten-ance on the breakers. No work control concerns were identifie However, the inspector did note the following two concern The first concern involved the response time testing of the breaker
- because the applicable procedure, OP-4525, Rev. 7 Surveillance Inspection of Rod Drive ACB's did not specify an acceptance criteria i
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for the response time testing. However, the maintenance personnel
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were using OP-5010, Rev. 6, Maintenance Department Corrective Main- ;
tenance to control the shunt trip coil replacements and specified an i
acceptable response time of .060 seconds. According to the cognizant J
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MSD engineer, the value selected was a reflection of his knowledge of '
" prior equipment performance, but to some degree it was a subjective determination. As a result of further questioning on this matter, the licensee showed the inspector a Westinghouse proprietary document
- that demonstrated the value used was well within required response
, time for the reactor trip switchgear. Subsequently, the licensee
issued Rev. 8 to OP-4525 which incorporated an acceptance criteria for the response time required for the reactor trip breaker This action resolved inspector concerns on this matter.
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The second concern involved the licensee's practice of testing the
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RTB's overcurrent trip device using an alternating current multi.-amp tester. Since .the overcurrent trip devices on the RTB's were direct' ;
i current devices, the inspector was concernad about the acceptability of the practice and its limitations, should there be any. In response -
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4 to the inspector'.s, concerns, the MSO provided a written evaluation of .
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the test method on March 23, 198 The inspector reviewed this evaluation and concurred with the evaluator that no' issues were iden-
- tified that were of safety significance, however, further evaluation is warranted to fully evaluate the test methods and overcurrent trip j
setpoints. This remains an Unresolved Item pending completion of the ,
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NRC's review of this issue (50-29/88-05-03).
The inspector had no. further questions of the licensee at this time as- a result of reviewing their maintenance practices on the RTB ,
- Surveillance Observations .
i The inspector observed tests or parts of tests to assess performance in !
accordance with approved procedures and LCOs, test results (if completed), ,
- removal and restoration of equipment, and ' deficiency review and resolu-
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tion. The following tests were reviewed:
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DP-5001, Re , Vibration Monitoring Program . performed on l February 25, 1988 i r
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OP-4204, Rev. 35 Test or Special Operation of the Safety Injection Pumps and Determination of ECCS Subsystem Leakage performed on
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February 25, 1988 1 --
OP-4656, Rey, 7, Functional test of the NRV Main Steam Line Pressure
{ Channels performed on February 25, 1988 and March 10, 1988 !
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OP-4666, Rev. 6, Functional Test of the Fire Suppression and Detec- .
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tion System, Attachment C, performed on March 10, 1988
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OP-4644, Rev.13, Functional Test of the Fire Detection Instrumenta-j tion performed on March 10, 1988
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OP-4269, Rev. 2, Safety Injection Building Ventilation System Opera-I
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bility Check performed on March 10, 1988
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Based upon a review of licensee activities in this area, the inspector
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During the performance of OP 4204 on February 25, 1988 to accomplish the routine weekly testing of the low ' pressure and high pressure safety injection pumps for operability and to determine the ECCS sub-system _ leakage, the inspector observed boron precipitation on the ends and side of several low pressure safety injection (LPSI) pump The boron precipitation was noted to be in the area of the gasket ;
where the top and bottom halves of the pump casing- are bolted t together. Additionally, considerable boron was noted in the drip pans surrounding one of the LPSI pumps and on the hose and hose clamp '
i- from the outboard gland leak off. Discussions with licensee repre-sentatives indicate that they were unaware of the boron precipitation *
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around the pump casing; however, major maintenance on these pumps can only be done during an outage and that some leakage around the pump's mechanical seals was expected. Additionally, the licensee indicated s
that some dried precipitation on the outside of the pump was con-4 sidered acceptable; their threshold for when this becomes a major -
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problem is when there is visible wet leakage around the seal / pump J casings or when the identified leakage is greater than that allowed
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by TS. The inspector had no further questions at-this time, i
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During per formance of procedure OP-4656, on February 25,1988 to '
accomplish the routins monthly TS surveillance requirement, MS-PS-24 (channel 2, No. 4 steam line pressure switch) actuated at 263 psi After this initial t#st of the pressure switch it was immediately retested and found to function within acceptable setpoint limit On March 24, 1988 during the next monthly surveillance of the press-
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ure switches, MS-PS-34 (channel 3, No. 4 steam line pressure switch)
actuated at 192 ; ig, and then was reset to within acceptable set- ,
point limits by dC technicians. This switch was then retested repeatedly (approximately 15 times) and actuated each time within j allowable setpoint limits. These pressure switches are part of the i engineered safeguards and reactor protection systems.
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The inspector noted the following with respect to these pressure switches. The TS setpoint requirement for the main steam header
, pressure switches is greater thar or equal to 262.5 psig. Although j MS-PS-24 actuated just within TS setpoint requirements this pressure ,
- switch had been found abnormally low three timas in the past three
! month During a surveillance on December 3, 1987 this pressure ,
j switch was found to have actuated at 260 psig, below TS requirements
, (see inspection reports 50-29/87-16 and 50-29/88-02 for additional i details on pressure switch problems). Temporary corrective actions ,
for the pressure switch failures in December,1987 included shorten-
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I ing the TS surveillance testing interval on the pressure switches t
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f rom monthly to bi-weekly. A review of surveillance results between ;
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December 3, 1987 and this surveillance test indicated one other :
occasion of excessive drift with the MS-PS-24 pressure switch. Al- '
though the setpoint was within TS, it was out of the administrative i limits of 300 6 psig.
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Discussions with the licensee -indicated that the TS surveillance l testing interval on the main steam line pressure switches had been returned to a monthly interval. The licensee attributed the last low !
I setpoint on MS-PS-24 to be caused by instrument drift. When pressure ;
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switches sense a constant pressure-continuously, the setpoint tends to drive away from the pressure _ it sees. The normal pressure sensed I
during full power operation is 540 psig. The pressure sensed during i
- normal plant startup and shutdowns is typically 760 psig. The set '
point for switch actuation is 300 psig decreasin The licensee evaluated the excessive drift of MS-PS-24 and determined l that.the pressure switch should be replaced. The pressure switch was replaced in accordance with Ap-6007, Rev. 5, I&C Department Correc-tive Maintenance,. and functionally tested in accordance with procedure OP-4656 on March 10, 1988.
l During the pressure switch surveillance on December 3,1987 MS-PS-34 ,
was also found below TS setpoint requirements; it was fuand to have
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i actuated at 240 psig. Although MS-PS-34 actuated at 192 psig during i the surveillance on March 24, it was not immediately replaced by the ;
{ licensee at that time, even though the plant was in hot standb ;
) Discussions with the licensee indicated that MS-PS-34 would be re- f
placed one week later during the next scheduled high risk surveil- '
, lance day.
The NRC had several concerns in this area. Historically, problems /
concerns have been recurrent with respect to this pressure switch. - i As stated above, in December, 1987, the switch was found to have l'
i actuated at 240 psig and during surveillance on March 24, it again failed to actuate within TS requirements. Additionally, since l
,i MS-PS-34 was found out of TS setpoint requirements in December,1987, !
the licensee has noted a widening deadband on this pressure switch ,
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i since that time. The de:dband is the difference between the pressure j the switch initially actuates at and the reset pressure of the L
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switc Normal deadband characteristics show the reset pressure to '
be approximately 50 to 60 psig above the trip pressure. On November ;
- 5, 1987 the deadband of MS-PS-34 was 58 psig; December 3, when the j pressure switch was out of TS setpoint requirements, deadband was 180 .
, psig. Subsequent surveillances since that time showed deadbands of i 1 179.5,104,190,187 and 196 psi Even after the trip pressure of '
this switch was readjusted to the as-left condition, the reset
, pressures were equal to or greater than 440 psig. Channels 1 and 2 pressure switches (except MS-PS-24) show reset pressures in the mid- l
, 300 psig range. The NRC questioned the appropriateness of not re- ,
- placing MS-PS-34 at the time the excessive low setpoint was dis- l j covered and the excessive drift was noted in the switch, since at l
i that time the plant was maintaining hot standby condition >. i i
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The licensee considered the switch operable due to the following ,
considerations: 1) the switch, once actuated, reset to 300 i6 psig decreasing, the administrative limit, 2) repeated actuations of this switch (approximately 15 times) showed it actuated within allowable setpoint limits and 3) the switch would continue to be operable for the following seven days when MS-PS-34 would be changed out and all twelve pressure switches would be tested at that tim This func-tional test one week later was considered prudent by the licensee since the plant had just been through a pressure cycle due to the scram and plant startup the week of March 22-25, 198 The licensee considered that they had an adequate data base on this switch to postpone pressure switch change out for one week until the next high risk surveillance da The inspector discussed the above concerns with NRC regional manage-ment, who supported the inspector's concerns and the need for the licensee to provide appropriate justifications for their actions. In response to NRC concerns, although the licensee felt confident that the pressure switch was operable and would actuate as designed, the licensee replaced MS-PS-34 on March 25. Just prior to removal of this pressure switch, the switch was found to have actuated at 292 psig, outside the licensee's administrative setpoint requiremen Furthermore, the deadband was found to be 200 psig. It should be noted that the pressure switch was found outside licensee administra-tive limits just one day af ter the switch actuated outside of TS requirements and then reset to within limit On March 26, 1988, after the second automatic reactor trip and while the plant was in hot standby, the licensee replaced two additional switches, MS-PS-32 and MS-PS-3 The licensee has been trending the trip and reset pressures of the main steam line pressure switches and has noted that the deadband on these two pressure switches has also been widening. Review of previously performed surveillances illus-trate that since December 1987, the reset pressures have been at or greater than 400 psig with deadbands greater than 100 psi Due to the problems being experienced with the main steam line !
pressure switches the licensee has decided to increase the surveil- ;
lance schedule on these switches, i h
With respect to previously documented problems on the main steam line
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pressure switches (inspection reports 50-29/87-16, 50-29/88-02), in a j letter dated January 27, 1988 from the licensee to the Automatic Switch Company (ASCO) the licensee requested a return authorization for two pressure switch assemblies and requested ASCO's aid in deter- ;
mining the root cause of the pressure switch failure The two
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pressure switches failed during the monthly . surveillance on l
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December 3,1987 and were subsequently removed and replace The licensee has also expressed to ASCO its desire to take part in any investigative work by witnessing disassembly of the switches and
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other possible tests. Also, pressure switches MS-PS-24 and MS-PS-34 ;
- will be taken to ASCO for investigation as to the cause of ' their i
excessive setpoint drif The previous two pressure switches that failed to actuate within TS setpoint requirements on December 3, 1987 were sent to ASCO the week of March 7, 1988; the current.two pressure switches will be hand carried to ASCO. The failure mode analyses on these four pressure switches is scheduled to be performed on April 5,1988 with two licensee representatives present to witness the activitie '
Fur P rmore, the licensee, upon review of maintenance request (MR 88-!J6) for the replacement of MS-PS-24, had expressed concern that
{ this was the third pressure switch of twelve to ~be replaced within i three months. The licensee had written Plant Design Change Request .
(PDCR)82-004 to install syphons and snubbers in the sensing lines ,
of all twelve main steam line pressure switches f, inspection report !
50-29/87-16). The installation of the syphons and snubbers was a j
recommendation of YNSD to stop suspected system transients from caus- -
,' ing further switch failur Licensee concern is, that if MS-PS-24 failed for causes similar to those of the two previously- failed i pressure switches in December, 1987, that the remaining pressure switches could be assumed to be experiencing similar degradatio *
Therefore, not only would the installation of syphons and snubbers in the sensing lines be required, but also, the replacement of all pressure switche The inspectors will continue to follow licensee actions with respect to the pressure switch failure The inspector had another concern in this area. During the perform-l ance of procedure OP-4656 to functionally test the non-return valve pressure channels / switches, the procedure requires the removal of all
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fuses at the non-return valve (NRV) cabinet, for the channel under i
! tes Pulling all fuses for the channel under test disables one of ;
j the three relays used to make up the two-out-of-three logic on each I main steam line and causes the loss of power to the entire channe '
- This prevents the ability to energize these relays, making the logic J
two out-of-two instead of the original two out-of-three. The licen-j} see should evaluate performing the functional test without removing power to the channel. Leaving power to the channel while performing
- the functional test will result in partial actuation of the logic
with only one of the two remaining pressure switches requi ed for
~j main steam line isolation. The licensee's resolution of NRC concerns relating to this matter remains an open item (88-05-04).
No violations were identified during surveillance observations.
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10. On-site Review Cor.11ttee Activities The inspectors attended regularly scheduled meetings of the Yankee NPS on-site review committee (PORC) on March 9, 14, 22, 26 and 28 to ascertain that the provisions of T.S. 6.5.1 were me During the meeting held on March 9, 1988, the inspector noted that the Engineering Manager and three engineers from the Yankee project group of the Yankee Nuclear Services Division attended the meeting and participated actively in the committee revie The item reviewed involved a design change proposal to design and install a system to provide post-accident waste cleanup capability. The involvement by corporate engineering staff, which encourages early plant input by PORC members in the conceptual design phase of the design process was considered by the inspector to exemplify the strengths that the licensee exhibits in the crea of engi-neering suppor No violations were identified in the review of this are . Review of Licensee Events Reports Licensee Event Reports (LER's) submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the descrip-tion of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated and whether the event warranted onsite followup. The following LER's were reviewe ,
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Event Report LER N Date Date Subject 50-29/87-04 02/18/87 03/20/87 Inadvertent ECCS Actuation 50-29/87-08 05/31/87 06/30/87 Loss of Station Service Transformers No. 3 and 6, and auto start of N EDG 50-29/87-09 05/22/87 06/20/87 Fuel Degradation (assembly A-731 in .
core position H-9) l l
50-29/87-10 06/01/87 07/01/87 Improper Switching caused automatic '
start of No. I and 2 emergency diesel generators LER 50-29/87-04: The details of this event are contained in Section l 8 of Inspection Report 50-29/87-02 and is further discussed in Section 3 of this repor The inspector had no further questions concerning this LE !
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i LER 50-29/87-08: The details of this event are contained in;Section j
! 76 of Inspection Report 50-29/87-06. The inspector had no further i
- questions concerning this LE ;
! LER 50-29/87-09: The details of this event are contained in Section "
? 76 of Inspection Report 50-29/87-06. .The inspector had no furthe I
! questions concerning this LE LER 50-29/87-10: The details of this event are contained in Section :
7b of Inspection Report 50-29/87-06. The inspector had no further questions concerning this LER.
, 12. Licensee Response to NRC Bulletins !
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The licensee's response to the following NRC Bulletins were reviewe ,
This review included: adequacy of the response to NRC bulletin require- l ments, timeliness of the response, completion of identified corrective- .
actions and timeliness of completio '
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NRC Compliance Bulletin No. 88-01: Defects in Westinghouse Circuit. Break-
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ers, dated February 5,1988. This bulletin required the licensee to con- l
! duct inspections of Westinghouse DS series circuit breakers. Licensees !
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who do not have circuit breakers subject to this bulletin were to provide !
, a letter to the NRC stating this fac On March 1, 1987 the licensee j l documented in its letter FYR 88-29 that the YNPS does not have any of the :
! subject breakers used in safety-related application '
l The inspector verified the licensee's response to the bulletin by inde-
pendently discussing the issue with knowledgeable plant personnel, review- i
- ing appitcable licensee documents and reviewing the status of equipment i
- and material maintained in the plant stockroo
This bulletin is closed.
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NRC Compliance Bulletin No. 87-02: Fastener Testing to Determine Conform- c ance with Applicable Material Specifications dated November 6,1987, This ;
bulletin was reviewed in Section 15 of Inspection Report 50-29/87-16 and ~
remained open pending the licensee's submission of the results of addi-
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tional testing and determination of safety significance. In addition, d
j j they were to report on procedure revisions for procurement, receipt ;
inspection and testing, j
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In accordance with the licensee's commitments, letter FYR 88-31 issued on ,
! March 7,1988 provided the additional information. This letter specified ,
I that: 1) the out-of-tolerance safety-related nuts were proof load tested, ;
- which demonstrated that there was no safety significance, and that no ;
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Itmits need be placed on their use as a result of the low carbon content; j 2) additional fastener testing was performed on nuts supplied by the t
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vendor of the out-of-tolerance nuts, with no new nonconforming conditions identified; and 3) procedure AP-0212, Control of Purchased Material, Equipment, and services will be revised to include random sampling and testing of safety-related fasteners to ensure compliance with applicable material specifications. The licensee's actions to revise this procedure is an open item (50-29/88-05-05).
This bulletin is close . Organization and Administration During the inspection period, the inspector reviewed changes to the licensee's staff or organization structure as described below. The review included verification that the licensee's onsite organization structure is as described in the facility TS and verification that personnel qualifica-tion levels are in conformance with ANSI N18.1-1971, as described in TS Section 6. As a result of the retirement of the Vice President / Manager of Oper-atioits, the licensee announced the promotion of the Assistant Plant Superintendent to Vice President / Manager of Operations, effective March 11, 1988. As a result of this promotion, the licensee announc-ed the promotion of the Technical Director to the position of Assist-ant Plant Superintendent and the promotion of the Assistant Technical Director to Technical Director, effective March 16, 198 On March 16, 1988, the licensee announced changes in the plant's organizational structure that became effective the same day. These changes reflect 1) the position of assistant technical director has been eliminated, 2) training and operations will report to the Assistant Plant Superintendent, 3) reactor engineering, chemistry, technical services and radiation protection will report to the Tech- ;
nical Director and 4) maintenance department will now report directly l to the Plant Suoerintenden l No inadequacies were identified by the inspecto .
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1 Participation in NRR/ Licensee Meeting I On March 16, 1987, the inspectors and the NRC:RI Reactor Projects Section Chief for YNPS attended the monthly meeting between the YAEC licensing engineer for YNPS and the NRC:NRR project manager. This meeting was con-ducted at YNPS, and included participation by the NRC:NRR Project Direc-torate I-3 Director and licensee senior corporate manager The meeting topics included (1) the current status of the application for extending ,
the operating licensee from November 1997 to July 2000, (2) the licensee's i request for an exemption from the implementation of the ATWS rule 10 CFR 50.62, (3) a discussion on the need for timeliness on the NRC review of the proposed change submitted in January 1988 that modifies the Technical
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Specifications totallow shipping spent control rods.from the YNPS, (4) the' ;
current status of other' submitted proposed Technical Specification changes e (5) the status of various Systematic Evaluation Program items, (6) the ;
licensee's progress on its program to upgrade emergency operating proced-
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ures,-(7) a discussion on the NRC's approval of the licensee's future test '
plans to meet the requirements of 10 CFR 50, Appendix J, and (8) other i licensing issues of mutual interest.to the licensee and NRC.
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In addition to the above items, the licensee's meeting agenda included - ;
discussions involving (1) the Yankee organization, (2) plant ' overview and j performance, and (3) the NRC Category 3 licensing proces !
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The inspector had no questions of the licensee on this ite !
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15. Licensee Self Assessment Activities
The inspector reviewed a number of systems and activities used or cen- !
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ducted by the licensee for critical self assessments of performance. The !
] following activities were reviewe !
i Work Activity Observation Program. This program was implemented at i j
' the plant on March 8,1988 and is intended to ensure that managers ;
and supervisors place emphasis on monitoring day-to-day work activ- ;
ities and correct improper work . practices. It was envisioned that {
- additional work practice deficiencies will be identified and cor-i rected by the more frequent and more effective management and super-
visory monitorin Consistency will be provided by senior plant j- l managers accompanying from time to time the department heads, super- !
i visors, and foremen during the observation activity. This program is 1 j a specific initiative of the Plant Superintendent. A February 8, 1988 l j memorandum to those plant personnel designated to be involved in the t
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i program provided the examples of types of activities to be observed, reporting methodology, and implementing guidance. Briefings were i
- held by the Plant Superintendent and program personnel to ensure that i
} observers fully understood the philosophy behind the program. This 1 i program provides for feedback to the training department on generic !
- performance problems.
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- In October, 1987, the licensee requested and obtained the services !
i of INPO staff to conduct an observer training course at the plan :
j This course provided the basic observation concepts, techniques, and l l skills and is used to strengthen the role of managers and supervisors !
in observing and assessing personnel performance. The licensee's ;
j program is built on a foundation of observation training, and has a
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high level of oversight and involvement by senior plant managemen 'l Two completed observation reports were reviewed by the inspector
' which involved field observation of chemistry sampling of the primary i system by a Rp department engineer and observations by the plant operations manager of boric acid mix tank makeup activity. In both cases, deficiencies were identified and recommendations generated to i
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l l \ Plant Inspection Program. The licensee is in the final stages of *
revising its existing plant housekeeping and cleanliness control pro- i gram. This program is controlled in accordance with procedure AP- t
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0040, Rev. 8, General Plant Housekeeping and Cleanliness Control Sur-ve A draft revision of procedure AP-0040 was reviewed by the inspecto It was observed that the current program will change in four significant ways, namely: 1) the level of supervisory personnel !
involvement is being raised by assigning only department managers, PORC members, or their alternates, to conduct the inspections; 2) the l number of inspection zones is being increased form three to eleven so as to increase effectiveness of program implementation in each ob-served area; 3) the focus of the inspections has been increased from fire protection and cleanliness to include material condition, indus-trial safety, and radiological control practices, and 4) the Plant Superintendent or his designated alternate will from time to time accompany designated inspectors, to ensure management standards are adequately understood. To minimize delays in identifying and correc-ting deficiencies, the revised program incorporates time elements for conducting inspections and reporting the results that are more re- :
strictive than the current program. This program will continue to be i l administered by the plant Health and Safety Supervisor. The inspec- r tor has observed an aggressive involvement in day-to-day plant activ- !
ities by this superviso As a result of the extent and nature of ;
this program expansion, the envisioned level of management involve- i ment, and the high level of dedication demonstrated by the admints- t trating supervisor, the inspector believes that this revised program l will become a licensee strength. Currently, plant housekeeping and ;
cleanliness conditions are at a excellent leve !
c. Training Department Plant Observation Program. Procedure DP-0526, I Rev. O, Training Department Plant Observation Program provides guide- !
lines and instructions for scheduling, conducting, and documenting l observation of plant activities by training department personne The training department developed and implemented this observation [
program to evaluate the effectiveness of completed training and to !
assess the need for additional training. Plant training instructors conduct formal observation for at least two weeks every six months,
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and during periods when non-routine activities are being performed by !
plant personnel. The inspector has observed training department personnel involved in field activitie ;
d. Observation of Licensed Operators. A performance observation program i of licensed operators is being developed for the conduct of perform- !
ance evaluation at both the Zion simulator training facility and at l the plan During the six simulator sessions conducted between ;
February 8 and March 18, 1987, each group was evaluated by either a !
senior station manager or a senior operator licensing trainer. De- !
tailed performance evaluations guidelines were use It was ;
envisioned that the evaluations will identify weaknesses that might j exist and enhance professional watchstanding technique !
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l l INPO Peer Evaluator progra As a result of discussions held with l F licensee representatives the inspector was informed that the Plant ;
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Superintendent, Technical Director, Maintenance Support Supervisor, '
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. and training personnel have been active participants in this progra The licensee maintains -strong support of this program, as evidenced ;
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by their active involvemen l
! l Yankee Projects Lessons Learne On- July 8, 1987, the Yankee .
] projects group of the Yankee Nuefear Services Division (YNSD) con- I ducted a Cycle 19 (the current operating cycle) planning and schedu-
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ling workshop for its personnel. The inspector reviewed the workshop agenda and handouts, and noted that one of- the workshop objectives
- included an assessment of cycle 18 lessons learned for feedback into !
cycle 19 planning and scheduling. A significant portion of the work- ,
shop was devoted to the cycle 18 lessons learned, and included pre- .
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sentations in the areas of engineering, expediting, planning and .
- scheduling, construction and licensing. Yankee Project Procedure N ;
17, has' an Attachment B, Lessons Learned, -which documents lessons ;
! learned from recent design change installations that reflect- a l
composite of experiences from cognizant engineers on recent job l
- The lessons learned are divided into the categories of
- project ;
management, design, vendor and consultant interface, plant interface, i
- NRC interface, construction interface, and schedulin On
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July 31, 1937, the project manager for the Yankee project issued an j updated lessons learned to all Yankee project personnel and selected l
- plant personnel, which reflected the results of the worksho {
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In a similar manner, the Yankee project engineering manager held a i
meeting at the plant on July 14, 1987 (approximately two weeks fol- l
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lowing the plant startup from the Cycle 18-19 refueling outage) to !
) discuss additional ways to share manpower resources in the future to !
] accomplish design changes. This resulted from the licensee's recog- i j nition that the plant maintenance support department lacks adequate !
] manpower resources to both follow all the design changes and perform l
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their other maintenance-related activities, i
[ Areas were identified where additional project engineering assistance i could be provided, with recommendations generated from this review !
i conducted by the plant and projects personnel. These recommendations
! were accepted for implementation by the YNSD project manager for the )
j Yankee project and the Vice President and Manager of Operations, j As a result of the inspector's review of programs and assessment activ-ities enumerated above, it was concluded that the licensee consistently
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ning, assignment of priorities, and control c' activitie No unaccept- l able conditions were noted as a result of reviewing portions of the licensee's self-assessment activities.
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16. Corporate and Engineering Support Activities The inspector conducted an assessment of the level of corporate and engi-neering support activities provided to the Yankee Nuclear Power Station by the licensee's YNSD. This assessment consisted of attending meetings with licensee personnel and reviewing documents. As a result of this assess-ment, the inspector noted the following items;
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YNSD organization and services provided to its sponsoring companies were reviewed. Approximately 450 individuals comprise the YNSD, including the environmental laboratory, with the 1987 YNSD budget reflecting the involvement of 131 equivalent personnel for support of plant operations, Significant resources and expertise are available to the operating organization from corporate and engineering support groups of YNS A large level of effort is provided by the various depar+ments of the YNSD in support of plant modification activitie In this regard, the Yankee projects group has well-stated goals, and benefits frum the use of modern project management techniques in their planning and scheduling activitie As documented earlier in this report, the Yankee projects group encourages improvements in performance in their support activities by constructively reviewing their prior experi-ences for the benefits of lessons learned. During the licensee's conduct of the cycle 18-19 refueling outage, which occurred between May 4, 1987 and July 3,1987, YNSD provided the equivalent of 470 man-days of engineering effort directly at the plant. Directly fol-lowing a refueling outage, bimonthly meetings are held between the operating and engineering organizations as part of planning efforts f for the subsequent refueling outag The licensee has ample participation in the various industry codes and standards committees. As of July 1,1937, the licensee supported the involvement of 36 individuals on a total of 63 seats of the various codes and standards committee In the NRC Inspection Team Report 50-29/88-02, the NRC conducted an assessment of licensee activities in the area of design changes and engineering support. This included review of configuration controls, 10 CFR 50.59 reviews, the modification design process, engineering involvement in plant activities, and QA/QC oversight. Subsequent to that inspection the Yankee projects group released their design basis document for the ECCS system. This document was a development ef fort for the licensee to define and conduct a systematic approach for specifying in one document the actual design basis of a plant syste l l
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a 46 Because of its relative importance, the ECCS system was selecte The inspector reviewed the document, determined that it was a useful quality document, and acknowledged the licensee's initiative to develop this configuration management too Similar evidence of the licensee's development of useful and quality efforts in the area of configuration management programs involved their development of the ,
environmental qualification basis document and the design basis index for the plan The inspector noted that this latter document is a multi-volume single source document that facilitates access to the YNPS design basis document In March,1987, the Yankee projects group forn.ed under its cognizance a plant life extension (PLEX) group to support potential licensee ef forts in this area. This action is in addition to the high level of support that the licensee has given for YNSD personnel involvement in industry efforts that involve evaluating the feasibility of extending a plant's life beyond the current 40 year operating license term. The group has identified the need to update and enhance the existing PRA studies performed for the plan These enhancements will involve the affects of aging on plant components and equipment and the improved modeling of the impact that human factor considera-tions will have on plant system One of the resources that the YNSD maintains for its sponsoring com-panies is its generic licensing group. On a quarterly bssis, this group issues a generic licensing status report on NRC requirer.ents, generic issues, unresolved safety issues, and rule-making. The in-spector reviewed the December 15, 1987 and March 15, 1988 quarterly status reports issued by this group, and found them to be useful compilstions on issues that currently, or could in the future, impact on the Yankee facilities. A notable activity of this group is their in,olvement in industry efforts to develop guidelines to ensure the propar conduct of 10 CFR 50.59 required safety evaluations. This industry effort is endorsed by the NRC as a method to resolve staff .
concerns in this are No unacceptable conditions or concerns were identified during the conduct of this assessment, The corporata and engineering support organizations are viewed by the NRC as a licensee strength, i 17. Open Items l l
I An open item is a matter that requires further review and evaluation by )
the inspector, including an item pending spe,:1fic action by the licensee 1 and a previously identified violation, deviation, unresolved item and i programatic weakness. Open items are used to document, track and ensure l adequate follcw-up by the inspector. Open items are discussed in sections 9 and 12 of this repor I I
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- 47 18. Management Meetings During the inspection period, the following management meetings were con- ;
ducted or attended by the inspectors as noted below: i
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On February 26, 1988, the inspector discussed items of mutual inter-est during a drop-in visit at the resident office by the President, f Yankee Atomic Electric Company.
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A meeting was conducted in the resident office on February 26, 1988
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by the Manager Administrative Services and the Security Manager for the purpose of informing the inspector about the licensee's plans for a restructuring of the security organization.
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The inspector attended an exit meeting held on March 4,1988 by NRC:
R1 emergency preparedness specialist inspectors at the conclusion of :
Inspection 50-29/88-06, which included a review of the licensee's
- emergency preparedness program and actions taken to resolve areas of NRC concer At periodic intervals during the course of the inspection period,
, meetings were held with senior facility management to discuss the inspection scope and preliminary findings of the resident inspector .
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