IR 05000271/1997006

Insp Rept 50-271/97-06 on 970720-0906.No Violations Noted. Major Areas Inspected:Licensee Operations,Engineering, Maintenance,& Plant Support

ML20217E716
Person / Time
Site:	Vermont Yankee
Issue date:	10/01/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20217E693	List: IR 05000271/1997006 ML20217E689 ML20217E701
References
50-271-97-06, 50-271-97-6, NUDOCS 9710070152
Download: ML20217E716 (35)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket N Licensee N DPR 28 l

Report N Licensee: Vermont Yankee Nuclear Power Corporation Facility: Vermont Yankee Nuclear Power Station Location: Vernon, Vermont Dates: July 20 - September 6,1997 Inspectors: _ William A. Cook, Senior Resident inspector Edward C. Knutson, Resident inspector

--John G. Carusoi Division of '2.aactor Safety -

Laurie A. Peluso, Division of Reactor Safety Approved by: Curtis J. Cowgill, Ill, Chief Projects Branch No. 5 Division of Reactor Projects i

9710070152 PDR 971001 G ADOCK 05000271 PDR

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EXECUTIVE GUMMARY Vermont Yankee Nuclear Power Station NRC Inspection Report 50 271/97 06 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.= The report covers a seven week period of resident 1 inspection and includes results of announced inspections by regional specialist inspector Operations The licensee's response to a lightning strike at the plant was generally good, but the on-

- shift control room staff missed a resultant automatic swap-over of the high pressure coolant injection (HPCI) pump suction valves. The HPCI system safety function was determined to be unaffected and its declared inoperability lasted for less than three hours as a result of prompt I&C technician response. Control room panel walkdowns and -

awareness, particularly during and following lightning storms, was viewed as an area for

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improvemen "

" 7 The licensed reactor core thermal power limit was exceeded by approximately 0.4 percente

'(six megawatts) for a period of eight hours due to a hardware malfunction in the data acquisition system for the plant process computer. 'The problem caused one channel of feedwater flow to be under reported by approximately two percent, and was identified ,

o < during routine reactor engineering reactivity trending, Licensee response was prompt and  !

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comprehensive. 'This licensee identified and corrected violation is being treated as a Non *

Cited Violatio Maintenance An infrequently performed calibration of the "A" residual heat removal (RHR) system flow instrument resulted in a preventable mis-positioning of the RHR minimum flow valve. The-.

- control room staff's failure to have identified this emergency core cooling system reconfiguration indicated poor control board awareness. However, the oncoming shift'

SCRO promptly identified the problem and relieving crew responsiveness to this non-

. conforming condition was goo . The two control room operator _ attentiveness events (also reference Section 01.1) which occurred this inspection period indicate that human performance improvement initiatives -

- recently implemented have not yet been demonstrated to be fully effective. Continued VY management attention la warranted in this are On two occasions, the Vernon Tie was removed from service for short duration planned

' maintenance to repair a damaged conduit which carries the feeder cable. As an unanticipated result of these short duration outages, some non-safety related environmental monitoring equipment was de-energized. Although prior review per the LCO Maintenance Plan Guideline was not required, this planned maintenance activity could have ii

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been excmined more closely by the VY staff to have avoided these unanticipated consequence The licensee identified that TS-required daily instrument checks of the recirculation pump trip / alternate rod insertion (RPT/ARI) actuation system were not being performed. The instrument checks had been accomplished using analog indicators on the original RPT/ARI actuation system trip units. However, when these units had been replaced with units that had no indicators, the requirement to perform daily instrument checks had not been addressed. This licensee identified and corrected deficiency was of minor safety consequence, in that, upon performing the instrument checks the trip units all functioned properly. In addition, completed periodic calibrations have maintained and demonstrated system operability. Accordingly, this failure is being treated as a Non-Cited Violatio Licensee response to the f ailed stroke testing of primary containment isolation valves RV-39 and RV-40 was prompt and troubleshooting efforts were well planned and execute Control room operator action to comply with plant technical specifications and commence a controlled unit shutdown were appropriate and properly implemented. Compensatory measures to isolate the recirculation sample line penetration and monitor this condition daily were properly performed by the VY staf As a result of reviews of logic system functional testing (LSFT), four different systems +

were identified to have lacked appropriate surveillance testing of their actuation logic circuitry. Although appropriately dispositioned by the VY staff, these discrepancies will be ( examined collectively in a subsequent inspection to examine the adequacy of the licensee's i GL 96-01 response and commitment The licensee had previously established an administrative limit of 90*F as the maximum f allowable torus water temperature, pending resolution of questions concerning the basis of the current TS limit of 100'F. During this inspection, the 90'F limit was relaxed to 100'F, for periods not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, to accommodate surveillance testing which adds heat to the torus. This issue continues to be examined by the NRC staff and the associated unresolved item remains ope The licensee identified through wall cracks in the radwaste building ventilation ductwork leading to the plant stack. Those cracks provided an unmonitored radiological release pathway. Swipes and portable air samples revealed no detectable radioactivity. As a temporary measure, the licensee covered the cracks with duct tape. Pending completion of the licensee's investigation and NRC staff followup, this issue is unresolve Enoineerina -

The VY staff demonstrated an appropriately low threshold for ER initiation for the installation of a plug in the East switchgear room floor drain. The development of a basis for maintaining operation (BMO) likewise reflects a heightened sensitivity to system design control. Actions taken by the VY staff to resolve this condition were appropriat Programmatic weaknesses identified in the licensee's operating experiences (OE) review iii

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process appeL! to have been appropriately addressed via implementation of a new administrative procedure (AP-0038). A selected sample of recently dispositioned OE items identified a proper review and closure of the individual concerns. Licensea siffectiveness of industry OE followup remains an item of routine review by the NRC inspecuon staff. This inspection followup item is close The licensee has appropriately prohibited any future containment inerting or de-inerting operations at power, until the containment purge licensing basis and apparent analytical errors can be appropriately resolved. The identification of this licensing basis discrepancy by the site Technical Support staff reflected an appropriate diligence to researching and understanding the unit's containment purge licensing basis. The f ailure to have properly resolved the standby gas treatment system over pressure vulnerability prior to containment inerting operations, at power, on May 8,1997, demonstrated ineffective corrective actions and was cited. The poor initial resolution of this issue on April 24,1997, also reflected a weak licensing function / revie Plant Suooort The programs for radiological environmental monitoring and meteorological monitoring continued to be effective. The licensee identified and quantified cobalt 60 in the sediment of the North storm drain outfall. The technique used to isolate discrete particles in the .

sample was good, however the licensee overestimated the projected dose to the publi ' The quality assurance audits were thorough and of sufficient detail to assess program strengths and weaknesses. The licensee's functional area assessment did not meet the f expactations of the quality assurance department. The performance and quality assurance program of the contract laboratory was excellen Many of the actions taken in the past year indicated progress in resolving EOP discrepancies and improving standards, but continued management focus and attentic,n appeared to be needed to achieve VY's desired results in this area. URI 95-05-01 will remain open pending the satisfactory completion of VY EOP action items, including issue of the new EOP program procedures, resolution of allidentified discrepancies in the OEs and appendices, as well as, resolution of the two concerns identified during this inspection regarding table SC-1 (Limiting reactor building area temperatures and combinations table in OE 3105) and the existing procedural guidance on containment venting (VY accident management guideline). There were also observations regarding EOP useability identified in NRC inspection report 50-271/97-09, not discussed in this repor As a result of an event at Haddam Neck Nuclear Power Station which involved the inadveitent initiation of the halon fire suppression system in the control room, the inspector l'

reviewed the available fire protection systems, equipment, and procedures for the VY control room to assess its vulnerability to a similar event. No automatic fire suppression systems are installed in the VY control room, but appropriate portable fire fighting equipment is available. An automatic fire detection system is installed and properly maintained, and the control room staff appears to be adequately prepared to address fires in the control roo iv

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--TABLE OF CONTENT 8

- EX EC UTIVE SU M M ARY - . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ll

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TABLE OF CO NT ENTS . . . . .- . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v i Summ ary of Plant St atu s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l. . Operations .....................................................1 l 01- Conduct of Operations = . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 Eautoment Problems Resultina from a Llahtnina Strike ......... 1 01.2 Reactor Core Thermal Power Limit Exceeded . . .-. . . . . . . . . . . . . 3 --

L 11. M ai nt e n a nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 -

M1 - Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

- M1.1 - Calibration of "A" Residual Heat Removal (RHR) Flow Instrument .4 M1.2e Vernon Tie Line Removed from Service ................... 5 M1.3 2 Licensee Identified Missed Instrument Check ..............5--

'M1.41 Failure of Recirculation Loon Samole Valven RV-39 and RV-4 w

, inservice Testina (IST) Stroke Tests , . . . . . . . . . . . . . . . . . . . . . 7 -

M1.5 Loale Svatem Functional Testina Deficiencian . . . . . . . . . . . . . . . 8 M1.6 - (Undate) Unresolved item 98-03-04: Torun Water Temnerature -

Administrative Limit Reduced .........,,.......,,.....-9 M1.7 : Cracks identified in Radioactive Waste Storaae Buildina Ventilation D u c t i ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 M1.8 . Surveillance observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 lll. ' Engi ne e ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 E7: Quality Assurance in_ Engineering Activities . . . . . . . . .-. . . . . . . . . . . .11  !

E7.1 Switchamar Room Floor Drain Plua . . . , , . . , . . . . . . . . . . . . ." 11

'E8 - Miscellaneous Engineering lasues .: . .:. . . . . . . . . . . . .. . . . . . . . . . . . . .12 -

i E8.1 (Closed) IFl 98-200-05: Weaknesses in the Effectivanaan of the  !

Oneratina Exner!ances (OE) Process . . . . . . . . . . . . . . . . . . . .- . =.12

_ E,8,2 (Undated) IFl 97 03-01: Potential Over oressurization of Standbv Gas Treatment (SBGT) Svntam . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 13

- lV. _ Plant Support ...........-......................................14- -

R11 = Radiological Protection and Chemistry (RP&C) Controls. . . . . . . . . . . . . 14

- R1.1. Imolementation of the Radioloaical Environmental Monitorina Prooram

.....-.:.........................................14 R1.2 Soecial Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 R1.3 Meteoroloaical Monitorina Proaram (MMP) ................ 17 R5- Staff. Training and Qualification in RP&C . . . . . . . . . . . . . . '. . . . . . , . . 18 R6 RP&C Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . 18 R6.1 Oraanization Chanaes and Resnonsibilities .... ,,......... 18 v

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R7 Quality Assurance in RP&C Activities . . . . . . . . . . . . . . . . . . . . . . . . . 19 R7.1 Quality Assurance Audit Proaram .....,,............... 19 R7.2 Quclity Assurance of Analvtical Measurements . . . . . . . . . . . . . 20 P3- EP Procedures and Documentation . . . . . . . . . . . . . . . . , . . . . . . . . . 21 P (Undated) Unresolved item 95-05-01 and Insoector Followuo item 97- j 01 -0 2 . . . . . . . . . . . ..............................21 F2 - Status of Fire Protection Facilities and F.quipment ...............,.24  ;

F2.1 Review of Control Room Fire Fiahtina Eautoment and Procedures . 24 V. M anagement Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5 X2 Review of Updated Final Safety Analysis Report (UFSAR) . . . . . . . . . . . 25 INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5 ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

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PARTI AL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 LIST OF ACRONYMS USED .........................................26 vi D

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Report Details Summarv of Plant Status During this inspection period, Vermont Yankee (VY) operated at full power with the exception of power reductions to conduct planned surveillance testing and a Technical Specification (TS) forced shutdown initiated on August 28,1997. The forced shutdown

- was terminated within a few hours, after the plant staff was able te obtain full closure of the inside containment recirculation loop sample isolation valve RV-39 (see Section M1.4).

A Region I based specialist inspector was on site the week of August 4 to conduct a routine inspection of the radiological environmental monitoring and meteorological monitoring programs. Another specialist inspector from Region I was on site the week of August 25 to conduct a follow-up inspection in the area of emergency operating l - procedures. Four senior reactor operator license candidates were examined by Region I license examiners during the week of September 2. The results of these license

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exarninations will be documented via a separate report.

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During the weeks of July 28 and August 18, a specialinspection was conducted to follow-up on the open items associated with the Fire Protection and Appendix R Programs. The -

results of this inspection will be documented under NRC Region i Inspection Report No. 50, 271/97 80. During the week of August 25, specialists inspectors from the Region I and Headquarters offices were on site to review the site access authorization program in response to the Carl Drega incident in Northern Vermont and New Hampshire, the previous l- week. The results of this review were documented in Inspection Report No. 50 271/97 -

t 0 . Operations 01 Conduct of Operations'

01.1 Eauioment Problems Resultina from a Liohtnino Strike Backaround and insoection Scone (93702)

At 9:05 p.m. on August 16, lightning struck the plant resulting in a number of minor equipment problems. At 12:06 a.m. the control room staff made a 10 CFR 50.72 notification (ENS No. 32779) identifying that they had declared the high pressure coolant injection (HPCI) system inoperable because the system suction had shifted from the condensate storage tank (CST) to the torus presumably due to the lightning strike. The inspector conducted a followup of this event to assess VY staff handling of this event and their corrective action ' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic I

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. Obmarvations and Findinas The inspector determined from control room log' reviews, work order summary

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sheets, and discussiens with the VY staff that the following components were : I

- adversely impacted by the August 18 lightning strike: HPCI suction swap-over,  !

caused.by a power supply spike to the CST level transmitter; one cooling tower fan

. tripped and four fan operating indication lightbulbs blew; the discharge canal liquid l

- effluent monitor; the stack gas flow monitor; and the control panel Vernon hydro .

megawatt output meter. _ The inspector conormed that the control room staff took'

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_ appropriate action upon identification of the above equipment problems. Unit power had to be reduced because of the cooling tower. fans operation (one fan p _ automatically tripped and the four fans which lost _ operating indication were taken to d

"Off") lhe stack gas flow monitor was determined inoperable and a TS 30-day -!

l ~ limiting condition for operation was entered into. The out of-service liquid effluent L

monitor was compensated for by daily grab samples. The HPCI system suction-swap over was not immediately recognized by the on-shift crew.' It was identified L- - ?LE

- during the panel walkdown by the next shift's senior control room operator,v #

approximately two and one-half hours aftar the lightning strike. Upon identification, the control room staff took appropriate action to declare HPCI inoperable, pending troubleshooting and confirmation of system operability.-  :

= Instrumentation and Control (l&C) technicians determined that the most probable cause of the HPCI_ suction swap-over was a power supply spike on the CST level- -

,; transmitter. No damage to the power supply or transmitter was found and a .

calibration was performed to demonstrate proper operation of the transmitter and its ,

automatic control function The inspector observed that this was the second example in ten days (reference the August 6 RHR minimum flow valvs event, report section M1.1) where the on shift operating

crew did not promptly observe a change in ECCS configuration. The fact at the same SCRO identified these conditlows appears to be coincidental, but =

clearly a positive reflection on this individual's diligence to control room duties and

= attentiveness. Follow-up by the inspector determined that the operations staff does -

not have an established practice of maintaining heightened control panel sigilance during_or after lightning storms, in spite of the historical susceptibility to this natural phenomena. Operations management acknowledged this observation as an area ' .

which could easily be enhanced.'

Prior to the conclusion of the inspection period, all of the_affected systems were -

restored to service. The inspector learned that the systems engineering staff had

' initiated a task force to review the known lightning susceptible plant equipment and develop an action plan to improve their reliability.- Conclusion

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The licensee's response to the August 10 lightning strike was generally good, but the on-shift control room staff missed the HPCI system automatic suction swap-over. The HPCI system safety function was determined to be unaffected and its declared inoperability lasted for less than three hours as a result of prompt l&C technician response. Control room panel walkdowns and awareness, particularly during and following lightning storms, was viewed as an area for improvemen .2 Reactor Core Thermal Power Limit Exceeded Insoection Scoce (93702,71707)

On September 2,1997, the control room staff notified the NRC in accordance with 10 CFR 50.72 (ENS No. 32860) of VY's discovery that the unit was operated outside its design basis. Specifically, the licensed reactor core thermal power limit was exceeded (eight hour average from midnight to 8:00 a.m. on September 2) by six megawatts thermal (lice.ised limit of 1593 megawatts thermal). The inspector reviewed the licensee's response to this even Observations and Findinas The cause of the thermal limit being exceeded was traced to a failure in the ITG 9500 module of the "B" data acquisition system (DAS) which inputs to the plant process computer (emergency response facility information system - ERFIS). The failure occurred shortly after midnight and caused the "A" feedwater flow signal to be under-reported by approximately two percent. The feedwater flow signalis a major contributor to the reactor heat balance calculation and resulted in the epproximate six megawatt thermai error. Coincidental to the "B" DAS module failure, a one percent reactor power reduction was initiated to perform weekly control rod exercising. This surveillance activity and power maneuver appeared to have masked the feedwater flow chang The error was identified during routine reactor engineering reactivity trendin Reactor power was reduced to 98 percent at 7:55 a.m. at the request of the reactor engineer, pending further examination of the heat balance calculation and associated inputs. The determination of the reactor core thermallimit being exceeded was completed by afternoon and the NRC notification processed. The f ailed "B" DAS module was replaced and reactor power restored to 100 percent by September Conclusions Licensee response to this self-identified reactor core thermal limit viv. tion was prompt and comprehensive, as discussed above. The safety consequenc3 of this thermal limit having been exceeded was minimal and reactor coolant activity and chemistry was unaffected. The computer hardware failure was not predictable or within the licensee's control, however, good oversight by the reactor engineering staff resulted in its early detection. Accordingly, this licer:see identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section j

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Vll.B.1 of the NRC Enforcement Polic II. Maintenance M1 Conduct of Maintenance M1.1 Calibration of "A" Residual Heat D mval (RHR) Flow Instrument Backaround and insoection Scoce (61726 ed 71707)

During the day-shift of August 6,1997, while pecforming a calibration of the "A" RHR system flow instrument (FIS 10-148A), the RO minimum flow valve (RHR-16A) stroked from its normal open position to closed, without being noted by the control room staff or technicians performing the calibration. The calibration was completed, but because of en apparent proceduralinadequacy, the RHR 16A was not returned to the open position. At approximately 4:00 p.m., the evening shift operations staff identified RHR-16A closed, declared the "A" RHR system inoperable, and initiated actions to investigate the cause for this condition. - Prior to declaring the "A" RHR system operable, the RHR-16A valve was stroked and timed.

l satisfactorily in accordance with Inservice Testing (IST) acceptance criteria and l restored to the normally open position, Observations and Findir,as l The inspector's review of the licensee's immediate ret anse to this event concluded l that it was appropriate and conservative. An Event Report (ER No. 971032) was ( ' initiated to investigate the cause for the calibration procedure inadequacy.- This procedure problem apoeared to have been rooted in a design change made in early 1996 to reposition RHR-16A from normally closed to normally open (reference inspection report 96-07) Control room operator performance was mixed. The day-shif t control room operators were not fully attentive to their panels and did not detect the repositioning of RHR 16A. The RHR minimum flow valves automatically re-position on the system flow signal, if an RHR pump is running. The inspector notes that no alarm or annunciator light alerts control room operators to the repositioning of RHR 16A. Only the red (open) and green (closed) valve position indicating lights provide evidence of minimum flow valve position in the control room. Despite the day-shift staff's oversight, the evening-shift senior control room operator (SCRO) identified RHR-16A closed during his control board walkdown after--

having assumed the watch. This identification of an improperly positioned valve and the shift supervisor's actions to resolve the problem were prompt and appropriat At the conclusion of the inspection period, the inspector verified that ER 97-1032 remained open and that the responsible reviewers were still examining the cause(s)

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5 Conclusions The once per refuel cycle calibration of the "A" RHR system flow instrument resulted in a preventable mis-positioning of the RHR minimum flow valve. The day-shift control room staff's failue to have identified this emergency core cooling systern re-configuration indicated poor control board awareness. However, the evening-shift SCRO's prompt identification of this problem represented appropriate board attentiveness. The evening-shift crew's responsiveness to this no conforming condition was goo The two control room operator attentiveness events (also reference Section 01.1)

which occurred this inspection period indicate that human performance improvement initiatives recently implemented have not yet been demonstrated to be fully i

effective. Continued VY management attention is warranted in this are M1.2 Vernon Tie Line Removed from Service

' On August 19 and 22, the Vernon Tie was removed from service for approximatelyc three hours each day for planned maintenance by Green Mountain Power (GMP)

Company. The inspector verified that the licensee appropriately entered into TS 3.10.B.3 limiting condition for operation (LCO). These two planned outages were of short duration and initiated to affect a repair to a damaged conduit which carries the Vernon Tie feeder cable. - Adequate advanced notice of this maintenance activity

- was provided by GMP Company. Morning meeting discussions about the Vernon -

Tie outages were observed by the inspector and the plant staff concluded that due to the short duration of these_ outages a formal review per the LCO Maintenance Plan Guideline was not needed. Station management concurred with this approac The inspector reviewed the LCO Maintenance Plan Guideline, revision 4, dated 8/28/96, and concluded that its use for this event was not required. However, as a result of these short duration Vernon Tie outages, the station's Project Save (computer. based program to ensure Vermont State environmental river water temperature limits are maintained) river water temperature monitors and three environmental particulate air samplers were de-energized. These monitors and samplers being de-energized were of no safety consequence, but clearly not anticipated by the VY staff. This planned maintenance activity could have been -

examined more closely by the VY staff to have avoided unanticipated consequence M1.3 Licensee Identified Missed Instrument Check Insoection Scone (93702,61726)

At 7:00 p.m. on August 27, the control roon, staff entered into a 24-hour limiting condition for operation (LCO) per TS Table 3.2.1. This LCO entry was base upon the conclusion that the TS Table 4.2.1, "once each da/' instrument checks for the

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Recirculation Pump Trip / Alternate Rod insertion (RPT/ARI) actuation system were not being performed. The inspector reviewed the licensee's response to this event, b. Observations and Findings Four reactor vessel level transmitter trip units (LM-2-3 68A thru D) and four reactor pressure transmitter trip units (PM-2 3 54A thru D) provide input to the RPT/ARI actuation system. The daily instrument checks verify that the level transmitters all read within seven inches and the pressure transmitters all read within 45 pounds per square inch (psi). The licensee identified that, not only were these daily checks not performed as required by TS, but that the checks could not be performed because of the absence of trip unit output analog indicator The inspector determined from discussions with the VY staff that the RPT/ARI actuation system was modified in response to Generic Letter 83-28, " Required Actions Based on Generic Implications of Salem ATWS Event," dated July 8,198 The specific modification involved providing diverse trip features. The original RPT/ARI actuation system trip units were replaced by units made by a different manufacturer than the reactor protection system trip unus. Although the previously installed RPT/ARI trip units had analog indicators, their replacement units did no Consequently, the TS RPT/ARI instrument checks were overlooked until identified

via the improved Technical Specifications (ITS) development staff's review on l August 27.

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The inspector reviewed the revisions to the RPT/ARI reactor vessel pressure and level calibration procedures (OP-43109 and OP-43111, respectively) which added a section to perform the daily instrument chocks via installation of a digital multi-meter (DMM) into existing test Jacks. With the DMM installed, the trip unit output voltage can be read, recorded, and then converted to a pressure or level reading for comparison to the other trip unit outputs. The inspector verified the initial successful completion of these checks by 10:45 pm on August 27 and that the LCO was exited. No functional problems were identified with the RPT/ARI trip unit Although this method of daily instrument check introduces the potential for human error and a resultant unit trip, it provides the licensee with an interim solution and basis to continue plant operations, until modifications to the RPT/ARI trip units aan be developed and implemented. The inspector verified that these daily checks have been appropriately tracked and implemented through the end of the inspection period, Conclusions The failure to perform daily instrument checks of the RPT/ARI actua > .n system was contrary to TS Table 4.2.1. This licensee identified and corrected deficiency was of minor safety consequence, in that, upon performing the instrument checks the trip units all functioned properly. In addition, completed pe.; odic calibrations performed per OP-43209 and OP-43111 have maintained and demonstrated system opcrabilit Accordingly, this failure constitutes a violation of minor significance and is being i

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treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. VY staff response to this identified deficiency was prompt and thoroug M1.4 Failure of Recirculation Looo Samole Valves RV-39 and RV-40 Inservice Testino (IST) Stroke Tests insoection Scoce (93702,71707)

The operations staff was conducting I1 service Testing (IST) quarterly primary containment isolation valve (PCIV) stroke time testing of the recirculation loop sample isolation valves RV-39 (inside the drywell) and RV 40 (outside containment)

on August 28, when both valves failed to isolate sample flow. The inspector reviewed the licensee response to this event, Observations and Findinas l

l The RV 39 and RV-40 stroke test failures occurred at approximately 4:00 a.m. on i

August 28, at which time the control room operators isolated flow from the sample-line by closing RV-60, a downstream manual isolation valve at the sample sin Concurrently, TS 3.7.D.3 LCO action statement was entered, requiring a shutdown to cold conditions within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspector verified appropriate actions were-initiated to commence the unit shutdown and discussed those preparations with the shift supervisor. The inspector also verified an appropriate 10 CFR 50.72 notification was made (ENS No. 32833) pertaining to the TS-required shutdow The inspector observed licensee discussions and reviewed their troubleshooting plans. As a result of their troubleshooting, the licensee staff was able to achieve and verify satisfactory closure of RV-39. Attempts to close RV 40 were unsuccessful, but with RV-39 closed, the TS required shutdown was stopped and the recirculation sample line penetration closed in accordance with TS 3.7.D.2 (an indefinite LCO) and monitored per TS 4.7 The inspector verified the control power fuses were removed for valve RV-39 to provide reasonable assurance that the valve remained closed under any design accident condition and to satisfy TS 4.7.D.2. The inspector determined that the VY staff plans to investigate the failure of RV-40. The inspector also determined that VY plans to modify RV-39 and RV-40 during the planned 1998 refueling outag The modification is intended to provide a positive means to determine valve position via indication in the control room, Conclusions VY staff response to the failed stroke testing of RV-39 and RV-40 was prompt and troubleshooting efforts wera well planned and executed. Control room operator action to comply with plant technical specifications and commence a controlled unit shutdown were appropriate and properly implemented. Compensatory measures to

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isolate the recirculation sample line penetration and monitor this condition daily were properly perforrned by the VY staf M1.5 Logic Svstem Functional Testino Deficiencies Insoection Scoce (93702,61726)

During this inspection period, the VY staff worked toward completion of their logic system functional testing (LSFT) reviews, committed to in response to Generic Letter (GL) 96-01, " Testing of Safety-Related Logic Circuits," dated July 10,199 As a result, three different systems were identified prior to the end of the inspection period to have lacked appropriate surveillance testing of their actuation logic circuitry. The inspectors reviewed the licensee's response to the LSFT deficiencies and verified that appropriate corrective actions had been taken to resolve them, Observations and Findinos At 11:05 a.m. on August 29, the VY staff concluded that a number of automatic l depressurization system (ADS) actuation logic relays and contacts had not been l adequately tested / verified per the existing surveillance test procedures. The

! inspector verified that the ADS was declared inoperable in accordance with VY technical specifications. By 12:35 a.m. on August 30, the l&C staff had completed revised surveillance test procedures and satisfactorily tested the affected ADS logic relays and contacts. ADS was declared operable based upon these results.

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At 6:40 p.m. on September 2, the control room staff was informed that four relays-16A-KA, B, C, and D) in the primary containment isolation system (PCIS) actuation logic for valves MS-V74 and MS V77 (main steam line drain isolation valves) had not been adequately tested per the existing surveillance program. These valves are normally closed and, as a consequence, they were protective tagged closed until the affected relays were demonstrated functional, inspector followup on the morning of September 3 identified that neither MS-V74 nor MS-V77 had formally been declared inoperable per TS 3.7.D.2, and the daily check (logged) of valve position per TS 4./.D.2 conducted. Both valves had been protective tagged closed, which provided reasonable assurance of their safety function being maintained. It had not been 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> since the control room staff was notified of this LSFT problem, so the TS 4.7.D.2 daily logging requirement had not been missed. Consequently, the contro room operators had not operated the unit in conflict with TS requirements while addressing this degraded safety system, inspector followup determined that the MS-V74 and MS V77 relays 16A-KA, B, C, and D were satisfactorily tested via work order 97 8209 on September 5. MS-V74 and MS-V77 were declared operable at 10:45 a.m. and the TS 3.7.D.2 action statement exite At 4:45 p.m. on Septeraber 3, the control room operators ceclared containment atmosphere dilution system valves VG-22A and VG 22B inoperable, based upon a

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determination that a number of PCIS actuation logic relays had not been satisfactorily tested. The inspector verified that the requirements of TS 3.7 D.2 and 4.7.D.2 were satisfied. Loth valves are normally closed and were protective tagged in the " closed" position, inspector follow-up confirmed that the LSFT requirements were satisfied by 2:30 p.m. on September 9 and the valves were restored to an operable statu Subsequent to the end of the inspection period, HPCI valves 21, 24, 57, and 58 were determined to have not been adequately tested with respect to LSFT requirements. On September 8 at 3:00 p.m., the HPCI system was declared inoperable and logic system testing initiated. By 4:02 p.m., the LSFT results for these four valves were determined to be satisfactory and HPCI declared operable, Conclusions To date, individual LSFT discrepancies have been adequately dispositioned by the VY staff. The operations staff's failure to promptly recognize the MS V74 and V77 operability concern and the necessity to enter into the applicable containment penetration Technical Specification (TS) action statement was viewed as poor TS implementation. The LSFT discrepancies will be examined collectively in a subsequent inspection period to examine the broader programmatic corrective actions and the adequacy of the licensee's GL 96-01 response and commitments. -

(IFl 97 06-01)

M1.6 (Uodate) Unresolved item 96-03-04: Torus Water Temoerature Administrative Limit Reduced

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During this inspection period, quarterly pump and valve surveillance testing of the high pressure coolant injection (HPCI) and reactor core iso!ation cooling (RCIC)

systems was performed on September 2. This testing was performed in accordance with OP-4170, "HPCI System Surveillance," revision 34, dated July 17,1997,and OP 4121, "RCIC System Surveillance," revision 36, dated July 17,1997. Both of these procedures were revised on September 2,1997, by Department instruction (Dl 97-164 and Dl-97-165, respectively) to reflect the recently relaxed torus temperature administrative limit for surveillance testing which adds heat to the torus BMO No. 96-05, " Increase in Maximum Torus Temperature Post LOCA,"

revision 1, dated July 18,1997, documented the basis for the relaxed torus temperature administrative limit. The previously imposed 90'F limit, under all operational conditions, was relaxed to 100*F during surveillance testing which adds heat to the torus (for a period not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />).

The inspector observed portions of the HPCI system surveillance testing and noted that during the HPCI turbine operation the average torus temperature rose from 80*F to 95'F. One train of the residual heat removal (RHR) system was in the torus cooling modo of operation for the duration of the testing. Upon securing the HPCI turbine, the torus temperature rise promptly turned and was returned to 80*F. The approximate 15 degree temperature rise was anticipated by the VY staff, based l

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upon historical surveillance data. Because of warmer seasonal Connecticut River water temperatures, RHR heat exchanger heat removal capacities become more-limiting and the HPCI testing challenges established torus temperature limits. Both

- HPCI and RCIC systems tested satisf actorily and were returned to their standby lineups. This unresolved item continues to be examined by the NRC staff and remains ope M1.7 Cracks identified in Radioactive Waste Storace Buildino Ventilation Ductina On August 29, the licensee made a 10 CFR 50.72 report (ENS No. 32842) -

identifying a condition potentially outside the plant's design basis. Specifically, maintenance workers re-roofing the radioactive waste (radwaste) building identified through-wall cracks in the radwaste building ventilation ductwork leading to the plant stack. The cracks in the ductwork (the largest crack measured approximately 1/16-inch wide by two inches long) provide an unmonitored radiological release pathwa The radiation protection staff was notified and took swipes on and in the vicinity of the ductwork and obtained portable air samples. No detectable radioactivity was a found, As a temporary measure, the licensee covered the cracks with duct tap The inspector determined that the basis for maintaining operation process was initiated to address this issue and to formalize the corrective action plan, including a root cause investigation. Pending the completion of the licensee's investigation and-resolution of this issue and NRC staff followup, this issue is unresolved (URI 97 06-

- 02) .

M1.8 Surveillance observations insoection Scone (61726)

The inspectors observed portions of surveillance tests to verify proper calibration of test instrumentation, use of approved procedures, performance of work by qualified personnel, conformance to LCOs, and correct post-test system restoratio Observations. Findinos. and Conclusions The inspectors observed portions of the following surveillance activities:

"A" emergency diesel generator monthly surveillance test performed on August 18,199 *

Average power range monitor gain adjustments performed on August 25, 199 =

inservice Testing (IST) stroke time testing of RV-39 and RV-40 performed on August 28,1997. (see Section M1.4)

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High pressure coolant injection system quarterly pump and valve testing performed on September 2,1997. (see Section M1.6)

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Performance of the above stated surveillance activities was found to be in accordance with station procedures. Testing anomalies were appropriately dispositioned by the station staf Ill. Eng'neering i E7 Quality Assurance in Engineering Activities E7.1 Switchgear Room Floor Drain Plug Insoection Scoce (71707)

On August 18 the inspector observed the Event Report (ER) screening meeting which reviewed ER No. 97-1090. This ER addressed the fact that there is a plugged floor drain in the East switchgear room for which neither plant drawings nor procedures reflect this configuration. The inspector reviewed the licensee's actions to resolve this event, Observations and Findinas Tne inspector observed that the identification of this apparent discrepant condition

and the initiation of an ER for dispositioning it was good. Even though the floor

! drain system is classified as non-nuclear safety (NNS), the potentialimpact of this

plugged floor drain on the safety related switchgear warranted further station management attention. The screening committee discussed the condition of the fioor d ain being plugged while a; 'aiting resolution (configuration contrary to station drawings) and concluded that Operating Procedure (OP)-3127, " Natural Phenomena," step 7.i. provided adequate basis to conclude that the floor drain being plugged may be purposeful. The committe3 initiated the Basis for Maintaining Operation (BMO) process to conduct a detailed design review and to develop an action plan to resolve the discrepanc BMO No. 97-35 was completed and approved by the Plant Manager on August 29, 1997. The BMO concluded that the East switchgear room plugged floor drain condition could not be traced to a specific activity and was not ider.*ified in OP-4152, Attachment 03, which is a periodic theck of installed floor do in plug Accordingly, the plug was removed to conform with station drawingi., and OP-4152, Attachment 03, is to be revised to periodically verify the proper floor drain condition, c. _ Conclusions The VY staff demonstrated an appropriately low threshold for ER initiation for the installation of a plug in :he East switchgear room floor drain. The development of a BMO likewise reflects a heightened sensitivity to system design control. Actions taken by the VY staff to resolve this condition were appropriat ___ ___

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E8 Miscellaneous Engineering issues E8.1 (Closed) IFl 96-200-05: Weaknesses in the Effectiveness of the Ooeratina Exoeriences (OE) Process Insoection Scoce and Backaround (92901)

As documented in inspection report 96 200, the licensee's OE process has not been fully effective since its inception following the Three Mile Island event (reference NUREG 0737, Task Action item I.C.5). At the time of that inspection, the licensee was developing a procedure to outline a more formal process for licensee review and dispositioning of industry operating events. The inspector reviewed Administrative Procedure AP-0038, " Operating Experience Procedure," revision 0, dated 3/20/97, and a sampling (11) of recent industry OE reports to assess how AP-0038 was implemented and the effectiveness of the specific review Observations and Findinas inspector examination of AP-0038 identified a reasonably well-structured OE revie process, with an appropriate level of detailed guidance. The OE coordinator provides the bulk of the administrative work in initial screening, assignment, and j tracking of OE items in accordance with AP-0028, " Commitment Tracking."

l Department Managers are responsible for detailed follow-up, examination for i

applicability, and assignment of corrective actions, if warranted. AP-0038 also specifies that an annual self assessment of the effectiveness of the OE process be conducted. The inspector determined that the first self assessment of the OE process is planned for October 199 Examination of selected open and closed OE reports identified an easily audited process and an appropriate level of documentation for closure of items. One of the eleven items reviewed was still open (OE item INF97048) and assigned a reasonable target date for completion. The ten closed items examined were found to have been properly assessed for applicability and the recommended corrective actions were appropriate. The inspector did note that three of the ten items reviewed (INF97019, INF97029, and OE8428) were closed by an acting department manager, who so happened to be the principle reviewer and author of the OE item's closure memorandum. This review and closure scenario is not prohibited by the OE process nor were the specific OE items' basis for closure determined by the inspector to have been improperly substantiated. However, the inspector did discuss with the OE coordinator that greater independence between OE item author and reviewer may provide greater confidence in the proper dispositioning of the item. This observation was acknowledged by the OE Coordinator and followup with the responsible department manager identified that he supported closure of the three OE items, as writte _

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13 Conclusions Programmatic weaknesses identified in the licensee's OE review process have baen appropriately addressed via implementation of a new administrative procedure (AP-0038). A selected sample of recently dispositioned OE items identified a proper review and closure of the individual concerns. Licensee effectiveness of industry OE followup remains an item of routine review by the NRC inspection staff. This inspection followup item is close E.8.2 (Undated) IFl 97-03-01: Potential Over-oressurization of Standbv Gas Treatment (SBGT) Svstem Backaround and Insoection Scone (92903)

L in early August 1997, the VY Technical Support staff was conducting a review of

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the licensing basis for primary containment purging limitations, in support of a

' supplement to Licensee Event Report (LER) 97-05, when they discovered that it -+

appeared that the unit had again been operated outside its licensing basis.

l- Specifically, on May 8,1997, the containment was inerted at power without.

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adequate resolution of a standby gas treatment system (SGTS) over-pressurization concern. -The control room staff reviewed this discovery and made an appropriate 10 CFR 50.72 notification (Emergency Notification System No. 32735) on August 7,199 The VY staff determined that per NRC Safety Evaluation Report (SER), dated

- October 28,1985, the post LOCA 10 CFR Part 100 radiological dose projections (Excl .sion Area Boundary thyroid dose - 148 rem, and Low Population Zone thyroid dose - 113 rem) were based upon the availability of the SGTS filter trains (reference NRC SER, damd June 1,1971, and NRC to VY letter, " Request for Additional Information on ti.c Containment Vent and Purge System at Vermont Yankee," dated February 1,1980). The October 28,1985 SER documented the NRC staff's technical basis and approval of Technical Specification (TS) Amendment No. 9 This TS amendment limited the opening of the 18-inch drywell purge valve (V16-19

- 7A) to 50 degrees while inerting or de-inerting, and summarized the radiological evaluation of the consequences of a LOCA while purging, among other things. As stated in this SER, the purge valve closure time is estimated at 10.5 seconds and the release is assumed to be a rapid pressure surge that destroys piping downstream of the containment isolation valves (including the SGTS trains which are designed to withstand only a 2 psi differential pressure). The projected EAB and LPZ dose contributions during this particular accident scenario were 9 and 8 rem, respectively. Accordingly, the NRC staff's SER concluded that these small contributions were inconsequential to the projected post-LOCA doses and well within 10 CFR Part 100 limits. However, as the VY staff identified on August 7, these containment purge and post-LOCA thyroid dose projections do not appear to be additive values, since the assumed post LOCA 10 CFR Part 100 EAB and LPZ

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14 thyroid dose values assume SGTS operation and the containment purge values do not, Observations and Findinas The inspector observed that the licensee has appropriately prohibited any future containment inerting or de-inerting operations at power, until the licensing basis and apparent analytical error can be appropriately resolved by the VY staff and then with the NRC staff. Accordingly, the inspection follow-up item remains ope The discovery of this licensing basis conflict reflects well on the Technical Support staff's diligence and thoroughness in achieving a better understanding the unit's current licensing and design basis for containment purge limitations. However, the inspector expressed concern that the issue was prematurely closed of by the Design Engineering and licensing staffs on April 24,1997. Discussions with VY senior management established that vacancies on the licensing staff have been an area of concern. As stated in LER 97-14, dated September 5,1997, corrective actions have been initiated to address this " contributing cause." The failure to have taken

' effective action to address the standby ges treatment system design vulnerability "

and to have precluded a plant operation (containment inerting while at power o.i l May 8,1997) subsequently determined to be outside VY's licensing basis was

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contrary to 10 CFR 50, Appendix B, Criteria XVI, Corrective Action, and is a violation (~410 97-06-03), Conclusion The licensee has appropriately prohibited any future containment inerting or de-inerting operations at power, unt i l the containment purge licensing basis and apparent analytical errors can be appropriately resolved. The identification of this licensing basis discrepancy by the site Technical Support staff reflected an appropriate diligence to researching and understanding the unit's containment purge licensing basis. The failure to have properly resolved the standby gas treatment system over-pressure vulnerability prior to containment inerting operations, at power, on May 8,1997, demonstrated ineffective corrective actions and was cite IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Imolementation of the Radioloalcal Environmental Monitorina Proaram Insoection Scoce (84750-2)

The radiological environmental monitoring program (REMP5 was inspected against the Technical Specifications (TS) and Regulatory Guide 4.1, " Programs for i

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Monitoring Radioactivity in the Environs of Nuclear Power Plants".

b. Observations and Finding 1 The inspector, accompanied by the Radiological Environmental Supervisor, responsible for implementation and oversight of the REMP, visited selected sites where air samplers, water compositors, a milk farm, a garden, and thermoluminescent dosimeters (TLDs) were located. The inspector discussed sampling techniques and noted the techniques to be adequate to collect environmental samples with minimum cross contamination. The observed air sampling equipment were well maintained and calibrated. The automatic water compositor was operable and collected surf ace water as required by TS. The TLDs were placed at the specified locations and milk samples appeared to be available at the specified locations as required by the Offsite Dose Calculation Manual (ODCM).

l The 1996 annual report of the REMP was reviewoo to verify the TS reporting

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requirements. The 1996 annual report provided a comprehensive summary of the

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results of the REMP around the site and met the TS reporting require.Pents. No

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omissions, mistakes, or obvious anomalous results and trends were n'o ted. The -

analytical results of samples from Januar/ through July 1997 were also reviewe The inspector noted that the types and frequencies of analyses were performed as required and the results showed no increases as a result of effluents from the plant,"

with the exception of Co.60 as described in Section R1.2 of this repor The 1995 and 1996 land use census were performed according to TS and the .

Procedure, " Land Use Census." Performance of the land use census was thorough -

and complete. No program changes (e.g., changes in sample locations) were required as a result of the censu The inspector reviewed the wind direction assessments (wind roses) from the pcst five years and compared them to the pre-operational wind roses to detect changes, -

if any, in the prevailing wind directions. No significant changes were evident. The environmental monitoring control station locations were reviewed against the prevalent directions and the inspector noted that the control locations remained valid in areas that were minimally impacted by the facilit Capelusion Based on the above review and discussions, the inspector determined that the licensee's performance in implementing the REMP continued to be effectiv Appropriate samples were collected from the locations specified by the ODCM and at the frequencies required by the T l l

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lR1.2 ' Special Report l inanection Scona (84750 2);

' The licensee measured TS reporting level of Co-60 in a routine river sediment *

sample taken in June 1997. The inspection consisted of a review of the licensee's:

-(1) measurement techniques of the river sediment; (2) projected dose calculation to,

- - tbs public; and (3) Special Report required by the.TS. -

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= Observations and Findinas J As part of the routine REMP TS Table 3.9.3 requirements, the licensee collected 26

- river sediment samples near the North Storm Drain outfall. All 26 sedim_ent samples were split between the licensee's contract laboratory, Yankee Atomic Environmental

' Laboratory (YAEL) and the State of Vermont Public Health _ Laboratory, according to -

an agreement between the licensee and the State for routine analysis of gamma-ray

' emitters. (One of the sediment samples, analyzed by YAEL, indicated an elevated - -i

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' level of cobalt (Co)-60nThe measured Co 60 activity was slightly higher than the - -

Vermont Yankee TS reporting level, 3,000 pCi/kg-dry for sediment in the outfal YAEL immediately recounted the sample on a different gamma spectrometry system -

to confirm the results. The recounted activity was about 5,610 pCi/Kg dry, highs. -

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ithan the first count result. : Differences in analytical results indicated that the Co-60-

might not be homogbneously distributed in the sediment sample, which was -

confirmed by the State of Vermont Public Health Laboratory ; The State laboratory

did n'ot detect Co-60 in any of the sediment samples. The licensee evaluated the - -

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' sample and YAEL sutroquently isolated discrete particles of Co-60 byl dividing thee

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sample into a small aliquot. The licensee isolated a 0.52 gram sediment sample -

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- with Co 60 discrete particles. On July 7,1997, the sample was counted and the'

Jactivity _was 3,820 pCl/ sample of sediment, equivalent to 8,092 pCl/Kg dr .The licensee collected additional grab samples from the shoreline and the outfall,  :

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and performed an in-situ gamma isotopic survey.1 No elevated Co-60 contamination e # was measured. The licensee collected an additional thirteen river sediment samples i ' from the outfall area to ensure that there were no public safety issues or .

environmental impact. - The inspector reviewed the sample results, -The results-E . Indicated no detectable Co-60 in any of the samples. The licensee will report all _ a l

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analytical results in the 1997 Annual Report as required by the TS.

i The inspector reviewed the licensee's projected dose calculation results.- The

! . licensee calculated the dose projections using the ODCM methodology. The projected whole body dose to the public (teen _ age)'was calculated based on -

assuming

(1) the Co-60 concentration was distributed homogeneously in the

sediment; (2) no occupancy factor; and (3) no attenuation from water or sedimen P The projected exposure rate at 1 meter was 3.4E-4'mR/hr and the projected annual j ' dose to the teen age group was 0.07 mrem. These values were considered to be

very low when compared to the annual total body dose commitment from natural y

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background radiation sources (approximately 200-300 mrem). The projected dose was weit below TS (Section 3.8,B.1.b.) limit of 3 mrem to the whol3 bod The inspector reviewed the licensee's Special Repert required by TS Section - 6.7.C.2.d. -The Special Report. dated August 8,1997, provided a comprehensive history of the issue, a detailed description of the sampling and analysis of the sediment samples, a description of the additional sampling and analysis results, and an adequate assessment of offsite dose. The Special Report also contained two corrective action items, which are to be completed by the end of 1997. The licensee stated that the subject of this report will be reported and described in the *

1997 annual Radiological Environmental Surveillance report, required by TS. - Conclusion-Based on the above review, the inspector made the following conclusions:

The licensee appropriately identified and quantified Co-60 in the sediment; i a

The licensee's technique to identify the discrete particles in the sediment i sample was good;

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The licensee's projected dose to the public was conservative and well within TS limits; and

Overall, the licensee's assessment was very goo R1.3 Meteoroloolcal Monitorino Proaram (MMP) insoection Scone (84750-2)

- The meteorological monitoring program (MMP) was inspected against the UFSAR and Regulatory Guide 1.23 commitments, Observations and Findinas Calibration and maintenance of the meteorological monitoring instrumentation was the responsibility of the Instrument and Controls Department. Calibrations of the wind speed, wind direction, and temperature sensors were conducted usir'g tne appropriate procedures. The inspector reviewed the calibration results from 1996 through 1997. Calibration methods were acceptable and the results were within the-required equipment tolerances. The meteorologicalinstrumentation were calibrated at the semiannual frequency recommended in Regulatory Guide 1.23. The physical-condition of the equipment appeared to be goo The Operations Department had the responsibility to perform daily channel checks of meteorological instrumentation in the control room. Channel checks were reviewed from July 4 through August 1,1997 to verify completion of the surveillances. The-

- Operations Department maintained the video graphic recorders in the control roo .

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18 Conclusions Based on the direct observations, discussions with personnel, and examination of procedures and records for calibration of equipment, the inspector determined that 3 overall, the licensee's performance of maintaining and calibrating the meteorological monitoring instrumentation was goo R5 Staff Training and Qualification in RP&C e, insoection Scone (84750-2)

The inspector reviewed the license's programs for the training of chemistry technicians and supervisors, Observations and Findinas l The licensee's technician training program included a required initial program and a i continuing program. The initial training included a comprehensive program which *

described aspects of the REMP, meteorological monitoring, TS, and ODCM and an examination. The continuing training reviewed the above aspects and includes +

industry events, emergency response, equipment modifications and procedure  ;

changes relative to chemistry and REMP. On the job training was also provide <

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The inspector also noted that the licensee was developing a continuing training program for the supervisors. The inspector will review this matter during a subsequent inspectio l

' Conclusions The licensee has a good training program for the chemistry technicians involved with the REM R6 RP&C Organization and Administration R6.1 Oraanization Chances and Resoonsibilities inscaction Scone (84570-2)

The inspector reviewed organization changes and the responsibilities relative to oversight of the REM . Observations and Findinas Changes in the organization regarding the oversight of the REMP were mado since the previous inspection in this area. The chemistry manager reports to the technical services supervisor. Reporting to the chemistry manager were the chemistry supervisor and chemistry programs supervisor. In June of 1997, the chemistry

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department eliminated the chemistry programs supervisor position and created four supervisors. The chemistry supervisor was renamed Balance of Plant (BOP)

supervisor and the others were the laboratory supervisor, non-radiological environmental supervisor, and radiological supervisor. The chemistry technicians work for the BOP, lab, radiological environmental supervisors. An environmental ,

(pecialist position has been posted to work under the non radiological environmental l supervisor. Overall, the responsibilities relative to oversight of the REMP have ensentially remained the same, Conclusions

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Based on the above review and observations, the inspeetor concluded that oversight of the REMP was effective and the responsibilities hue essentially remained with the same personne R7 Quality Assurance in RP&C Activities R7.1 Qualliv Assurance Audit Pro 9 tam I insoection Scoon (84750 2)

The inspector reviewed the quality assurance audit program against TS to assess performance in the REMP and MMP. The inspector evaluated this program through review of audits and the functional area assessment report, Observations and Findings The inspector reviewed ti e required audit of the REMP (VY 97 02, dated January 31,1997). The audit scope was focused and indicative of good planning. One audit finding was noted. The audit finding, which consisted of two parts, was technicalin nature and was compared to commitments of the UFSAR, procedures, TS, Regulatory Guides, and industry methods. The first part of the finding identified that appendix "A" of the REMP sampling procedure required an update to reflect the sampling contractor, Normandeau Associates, instead of the former contracto Aquatec. The second, identified three out of six vendor personnel were not provided training on the operation of the Service Water and Circulating Water Systems Traveling Screens. The response to the findings and corrective aJons were timely and appropriate. The REMP sampling procedure had been changed to reflect Normandeau and incorporated the contractors sampling methods into the procedure. Training of the three vendor peu.onnel had been completed. The auditors demonstrated the ability to place findings in the appropriate level of significance and assigned findings to the appropriate responsible organization The inspector also reviewed the functional area assessment report for the chemistry department, specifically REMP. The functional area assessment was intended to be a ce!f assessment of the REMP. The inspector cons;dered the self-assessment to be weak in that it did not consist of a thorough, objective review of the program. The

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licanseo quoted previous NRC inspection reports and the above audit (VY 97-02),

and based the assest.mont on the audits. The quality assurance auditor, who reviewed the assessment as part of a quality assurance requirement, indicated that the assessment did not fully meet the intent of a self assessment process. The quality assurance auditor planned to review the assessment with the chemistry department and communicate the intent of the self assessment proces The inspector reviewed the licensee's vendor audit of the Yankee Atomic Environmental Laboratory (YAEL). Tne audit (dated, January 31,1997) was conducted by the Laboratory Quality Control Audit Committee (LOCAC). No deficiencies of safety significance were identified. The audit was thorough and of excellent technical detai Conclusions i Based on the review of the audits and discussions with the quality assurance auditor, the inspector concluded that: (1) the technical depth was good, (2) the auditor effectively identified and assessed program strengths and weaknesses, (3)

the functional area self assessment was weak, and (4) the LOCAC audit of YAEL was excellen R7.2 QualityAssurance of Analvtical Measurements ' insoection Scapa (84750 2)

The quality assurance (QA) and quality control (OC) programs of the contract analyticallaboratory, Yankee Atomic Environmental Laboratory (YAEL) was reviewe Observations and findinos The Yankee Atomic Environmental Laboratory is the contract let, oratory that periormed the analyses of environmental samples. The performance of the laboratory continued to be excellent. During an inspection at Millstone, the inspector visited the laboratory and assessed the quality assurance program. (See Section R7.2 of the Combined inspection Report Nos. 50 245/96-09, 50 336/96-09, and 50-423/96 09 for details)

The inspector reviewed the quality assurance and quality control programs of the laboratory through review of the somlannual Quality Assurance report submitted by YAEL. The report included quality control charts, results of split and spiked samples and the inter-laboratory comparison progra The YAEL implemented an inter laboratory comparison program as part of the quality assurance program, required by TS, through continued participation with Environmental Protection Agency (EPA) drinking water program and a program provided by Analytics, incorporated. All the quelity assurance results were

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compared to the known values by the Environmental Supervisor responsible for

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oversight of the REMP. The inspector reviewed the analytical results of the EPA drinking water program and the results of the Analytics program. The results of the quality control and both inter laboratory programs were within the established acceptance criteria, with few exceptions. The exceptions were investigated and resolved, Conclusions Based on the above observations and review, the inspector determined that the performance of YAEL continued to be excellent. The !!:ensee maintained good quality assurance for the REM P3 EP Procedures and Documentation

, P3.1 (Undatedl Unresolved item 95-05-01 and Insoector Followun item 97 01 02 insoection Scone Unresolved item (URI) 95 05-01 concemed emergency operating procedure (EOPs)

including various technical concerns and a weak revision process. URI 95 05 01 had been reviewed previously and updated in NRC inspection report 50 271/96-05, sections 5.12 and 5.13. The inspector reviewed VY's corrective actions to the findings identified in NRC report 96-05, which lacluded an action plan developed by VY to address these shortcomings and an upgrade to their EOP program (VY memo, i BVY 96121, dated October 16,1996). In addition, the inspector reviewed the short term actions taken by VY to resolve the issues identified in inspector followup item (IFI) 97 01-G Observations and Findinos l

The inspector verified appropriate actions had been taken to resolve many of the concerns identified in NRC inspection report 50 271/96-05, sections 5.12 and 5.1 VY had corrected the two areas previously identified as uncorrected in the PST _

The operational emergency (OE) flow charts had been revised to correct EOP calculational errors, the calculations were audited by outside contractors to ensure accuracy, training was provided to the operators on the changes made to the OEs, controls had been developed to prevent repetition of calculational errors (in "draf t" form not yet issued), and revision 3 to administrative procedure AP 0009, " Event Reports," addressed the importance of timely documentation and reporting of activities that do not meet VY guidance and standards, in addition, VY reviews had identified a number of EOP discrepancies regarding the EOP & appendices (based on audits conducted by VY and consultants as part of their action plan). Correction of these discrepancies was in progress. The inspector's review concluded that the identified discrepancies did not affect actual EOP strategy, but when resolved would reconcile differences between the plant

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specific technical guidelines (PSTG) and OE flow charts that involve wording, logic / structure changes and bring VY more in line with industry standards. One major revision was planned for issue by November 1997, which will include issuance of the new EOP program procedures, as well as, a revision to the OE flow charts and appendices that will correct part of the identified discrepancies. Other major revisions, to correct fne remaining EOP discrepancies and to issue a new ATWS arid severe accident mitigation strategy, were planned for issue by December 31,1998, (VY had made the decision to delay implementation of their new EOP program and to delay issue of further revisions to the OE flow charts, in part, to

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prevent undue stress to the operator license class In progress at the time).

The inspector identified a concern in that OE 3105, " Secondary Containment l Control", table SC 1 (Limiting Reactor Building Area Temperatures and Combinations l Table) that did not appear to meet the intent of the BWR owners group emergency l procedure guidelines (EPG). Appendix "B" to the EPG states that the criteria for

! more than one area temperature exceeding maximum safe operating temperatures specified identifies the rise in secondary containment temperature as a wide spread problem which may pose a direct and immediate threat to secondary containment l integrity. VY's current methodology would require emergency depressurization of l the reactor pressure vesse' only for those combinations of areas that resulted in a .

loss of both redundant trains of a required safety function, all combinations of two -

areas are not applicable. For example, usmg VY's methodology the following four ,

areas could all exceed maximum safe temperatures simultaneously and still not reach a limiting combination requiring reactor pressure vessel emergency depressurization (torus room northeast area, northeast corner room 213 area, northeast corner room 232 area, and the above reactor water cleanup system pump area). This example would appear to be reflective of a wide spread problem which .

hypothetically affects four different areas simultaneously (equipment in those areas included torus cooling and spray "A" valves, torus water level and temperature plant accident monitors, residual heat removal service water system "A" & "C* pumps and valves, RHR "A" & "C" pumps and valves, and core spray system "A" pumps and valves).

As early as 1988 (NRC inspection report 50 271/88 200), table SC 1 had been identified as a significant deviation to the EPG. This was also recently identified as a discrepancy during a self assessment conducted by one of VY's outside consultants. The operation's manager agreed to research this matter further and advise the NRC of his intention Regarding the revision process previously identified as weak, item (3) of VY's action plan (VY memo, " Emergency Operating Procedures", BVY 96121, dated October 16,1996) had not been completed. A draft of the new "EOP Program Maintenance" procedure defined management oversight and staff responsibilities, established an EOP review committee provided instructions for handling and evaluation of EOP issues as well as initiating changes to the EOP, and revised the verification and validation (V & V) process. However, operation's management had not yet reviewed or commented on these drafts at the time of the inspectio ,

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IFl 97 0102 identified concerns regarding VY's EOP containment flooding st/eg The concern was that the rupture disc for the torus hard pipe vent might ruptwo before the OE directed containment venting. BMO (Basis for Maintaining Operation)

9715 was written to evaluate this problem. The short term fix was to shut the normally open rupture disc isolation valve TVS-86. The intent was to keep it closed for containment flooding and to keep it closed unless a complete loss of containment cooling occurred, efforts to restore containment cooling were unsuccessful, and containment pressure was increasing and approaching 30 ps The inspactor identified a concern in that containment venting guideline (VY i Accident Management Guideline), vent path 8E had not been revised to show valve TVS-80 closed to agree with BMO 9715 and other recently revised operating procedures. The drawing stillindicated the valve was normally open. The containment venting guideline contained numerous vent paths to be used to implement OE 3103 strategy in the event of high containment pressure or high containment hydrogen concentrations.

l Regarding sovere accident management, the inspector noted that the containment f venting guideline was not an issued procedure with any kind of period!c reviews or .

controls required. Specifically, the distinction between EOPs and the accident management guideline was not clear. For example, the individual vent paths were not approved or stamped or controlled in any obvious f ashion and did not receive the normal EOP V&V review process. However, it was reviewed and approved by the operations manager, plant operating review committee (PORC), and the VP of .

Operations. The operations manager agreed to address this matter further and edvise the NRC of VY's intentions, Concluslom Many of the actions taken in the past year Ind;cated VY's progress in resolving EOP discrepancies and improving standards. However, continued management focus and attention is needed to achieve VY's desired results in this area. Unresolved item 95-05 01 will remain open pending the satisfactory compleCon of VY EOP action items, including issue of the new EOP program procedures, resolution of allidentified discrepancies in the OEs and appendices, as well as, resolution of the two concerns identified during this inspection regarding table SC 1 (Limiting reactor building area temperatures and combinations table in OE 3105) and the existing procedural guidance on containment venting (VY accident management guideline). There were also observations regarding EOP useability identified in NRC inspection report 50-271/97 09, not discussed in this repor _-_ -

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F2 Status of Fire Protection Facilities and Equipment F2.1 Review of Control Room Fire Flahtina Eaulomant and Procedures inanection Scone and Backaround On August 7,1997, an event at Haddam Neck Nuclear Power Station occurred I which involved the inadvertent initiation of the halon fire suppression system in the :

control room. As a consequence, the control room was evacuated until habitability-could be re established (reference Emergency Notification System No. 32376 and

Preliminary Notification PN1049, dated August 8,1997). The inspector reviewed i

the available fire protection systems, equipment, and procedures for the VY control room to assess its vulnerability to a similar even i Observations and Findinos The inspector reviewed VY UFSAR, Section 10.11, " Fire Protection System,"

Technical Specification (TS) 3.13, and associated fire protection implementing -

procedures. The inspector determined that the VY control room has no automatic fire suppression systems, but does have installed five zones of fire (smoke)

detection established and maintained in accordance with TS 3.13.A, " Fire Detection," Table 3.13A.1._ A review of operating procedures and the applicable Pre Fire Plan (PFP CB 1) identified that portable fire f2ghting equipment (carbon ,

dioxide, halon, and dry chemical canisters) were staged in the control room in addition, self contained breathing apparatus (SCBA), six units with six spare air tanks, were also staged in the control room to support the normal operations shift-complement and the guard force member manning the secondary alarm statio The inspector conducted a walk through of the control room to verify the proper staging of fire protection equipment. One discrepancy was note.d where one of the two PFP CB 1 specified dry chemical canisters and was found to be replaced by a halon canister. The shift supervisor was informed of this discrepancy and he initiated action to resolve i The inspector determined that fires which f all short of a decision to evacuate the control room (reference Operating Procedure OP 3126, " Shutdown Using Alternate .

Shutdown Methods," revision 14, dated 10!26/96) are not specifically addressed by procedure. Discussions with the operating staff established that general fire brigade training and licensed operator training provide an adequate knowledge base to deal appropriately with smell fires in the control room. This training ensures proper knowledge and qualification for using SCdAs and portable fire fighting equipment, Conclusions The inspector verified no automatic fire suppression systems are installed in the VY control room and that appropriate portable tire fighting equipment is available. An

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automatic fire detection system is installed and properly maintained and the control room staff appears to be adequataly prepared (via procedural guidance and training)

to address fires in the control room.

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X1 Exit Meeting Summery l

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The inspector presented the laspection results of the radiological environmental monitoring program to members of the licensee management at the conclusion of l the inspection on August 8,1997. The licensee acknow! edged the findings i presente The resident inspectors met with licensee representatives periodically'throughout the inspection and following the conclusion of the inspection on September 29, 1997. At that time, the purpose and scope of the inspection were reviewed, and the preliminary findings were presented. The licensee acknowledged the preliminary inspection finding X2 Review of Updated Final Safety Analysis Report (UFSAR)

A recent discovery of a licensee operating their f acility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR description. While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed practices and procedures and/or parameter INSPECTION PROCEDURES USED 61726 Surveillance Observations 71707 Plant Operations 84750 2 Radioactive Waste Treatment, and Effluent and Environmental Monitoring 92901 Follow Up - Plant Operations 92903 Follow Up Engineering 93702 Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED OPEN IFl 97-06-01 Logic System Functional Testint, (LSFT) deficiencies, inspector follow-up URI 97-06-02 Cracks identified in Radioactive Waste Storage Building Ventilation Ducting

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i 6 VIO 97 06i 03 Failure to Take Effective Corrective Action for SBGT System Potential Over pressurization CLOSED IFl 96 200-05 Weaknesses in the Effectiveness of the Operating Experiences Process DISCUSSED >

IFl 97-03 01 Potential Over pressurization of Standby Gas Treatment (SBGT)

System URI 96 03 04 Torus Water Temperature Administrative Limit Reduced URI 95-05 01 Adequacy of EOP Revision Process IFl 97-0102 Potential to Excsed Containment Design Pressure During EOP Implementation PARTIAL LIST OF PERSONS CONTACTED G. Maret, Plant Manager F. Helin, Tech ~ Services Superintendent M. Balduzzi,- Superintendent of Operations E. Lindamood, Director of Engineering K. Bronson, Operations Manager M. Watton, Maintenance Superintendent M. Desilets, Radiation Protection Manager R. Gordus, Chemistry Manager G. Morgan, Security Manager LIST OF ACRONYMS USED BMO Basis for Maintaining Operation CFR Code of Federal Regulation-CR control ronm CS core spray EDG emergency diesel generator ER_ . Event Report .

GL Generic Letter HPCI high pressure coolant injection IFI' Inspector follow item IN information Notice LCO Limiting Condition for Operation LER Licensee Event Report LPCI low pressure coolant injection

.MCC: motor corarol center NRC ~ Nuclear Regulatory Commission

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Ni ? Non nucleer safety l PORC Plant Operations Review Committee QA- Quality Assurance RHR residual heat removal RP radiation protection l

T Technical Specifications UFSAR Updated Final Safety Analysis Report

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- URI unresolved item VY- Vermont Yankee I

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Ob.1 Review and Closure of Onen lasues Previously opened issues related to systems or components no longer requi,ed to maintain the plant safely were reviewed. These issues were determined to no longer have any safety or regulatory significance with the plant in the decommissioning mode. The following list of unresolved items (URIs), licensee event reports (LERs), and follow up of previously cited violations (VIOs) were reviewed and are considered administratively close /93 03 00 LER Expiration of DC solenold pilot valve EQ service life 50 309/93 09 00 LER inoperable emergency core cooling subsystems during pump recirculation valve stroke testing 50 309/93 11 00 LER Containment hatch "O" ring maintenance-50 309/94 09-00' LER Alternating ECCS subcomponents causes inoperable $

ECCS subsystems 50 309/94 16-00 LER Emergency feedwater isolation valvo leakage 50 309/95 07-00 LER A Train spray system valve actuation power supply from B 50 309/95 12-00 LER RHR spring reliefs determined inadequate 50 309/95 10-00 LER Potentialinability of CS-M 1 & 2 to perform safety function 50 309/96 02-00 LER- ECCS valve was found not positioned correctly ,

50 309/96 14 00 LER Potentially non-conservative symmetric offset trip set point 50 309/96 29 00 LER Main feedwater regulating bypass valve leaky

, _50 309/96 33 00 LER Entry into TS 3.0.A for both PZR heater banks inoporable 50-309/95 35 00 LER Requirement for post accident lodine sampling removed from procedure 50 309/96-06 02 URI Emergency operatirig procedure deficiency 50 309/96-06-03 URI Symmetric offset trip calculator 50 309/96-08-01 URI RWST level transmitters exposed to harsh environment 50-309/96 10-02 URI EQ for PCCW and SCCW pump motors

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50-309/96 12 02 URI Unplanned reactor power increase 50 309/94 15 02 VIO 10 CFR Part 50, Criterion V, Written Instructions l 50 309/95 26 01 VIO Water spill in contalnment

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