IR 05000334/1992024
| ML20128E298 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 12/01/1992 |
| From: | Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20128E293 | List: |
| References | |
| 50-334-92-24, 50-412-92-24, NUDOCS 9212080046 | |
| Download: ML20128E298 (18) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION 1 Report No Docket No License No DPR-66 NPF-73 Licensee: Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279 Facility: Beaver Valley Power Station, Units 1 and 2 Location: Shippingpert, Pennsylvani Inspection Period: October 13 - November 18,1992 Inspectors: Lawrence W. Rossbach, Senior Resident Inspector Peter P. Sena, Resident Inspector Approved by: . #s /M///h2 f)dhn F. Rogge, Chi &[/ ' 'Date Reactor Projects Section No. 4B 1pspection Summary ]
This inspection report documents the safety inspections conducted during day and backshift
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hours of station activities in the areas of: plant operations; radiological controls; surveillance and maintenance; emergency preparedness; security, engineering and technical support; and-safety assessment / quality verificatio .
h 9212080046 921201 PDR ADOCK'05000334- PDR b
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TAllLE OF SUMMARY Beaver Valley Power Station Report Nos. 50-334/92-24 & 50-412/92-24 ElanLQnerations Unit I ;tartup activities, following the reactor trip on October 9,1992, were conducted in a safe and deliberate manner. Excellent operator performance was evident during a Unit I feedwater transient. Prompt and appropriate operator action averted the need for an automatic turbine trip / reactor tri Judiological Controls 1.icensee's controls during a spent fuel pool cleanup project were found to be adequat Those contro:s prevented a worker from receiving an excessive exposure when a fuel assembly nozzle v.as inadvertently lifted to within 3.5 - 5.0 feet of the water surfac Maintenance and Surveillancs Switchyard maintenance was well planned and coordinated. The licensee's safety precautions and contingency plans were commensurate with those discussed in recent NRC information notices. A technician's error during the performance of a Unit I monthly surveillance testing resulted in overfeeding the 'A' steam generator to 68%. The safety significance of this event was minor as prompt operator actions restored level to within the programmed band before the fee <Jwater isolation / turbine trip setpoint of 75% was reache Securny The security force transition from Security Bureau, lacorporated, to Burns International Security Services has gone smoothly as the licensee's performance continues to be excellen Engineering and Tech ngal Supaul The replacement of the Unit I plant process computer represents a significant management commitment towards upgrading existent plant equipment. The impact of the computer replacement on plant operations was thoroughly evaluated and minimized. The 1992 anaual fire drill with the local volunteer fire departments was not well coordinated as several drill deficiencies were eviden Safety Assessment /Oualijy Verification A thorough review of assumptions for a safety assessment by the licensee identified that the steam driven auxiliary feedwater purr.p auto start signals for both units came from non Class IC relays. This was acceptably resolved by a circuit modification for Unit I and a basis for continued operation for _ Unit 2. The use of non IE relays to provide the reactor coolant pump bus undervoltage and underfrequency reactor trip signals was also found acceptable based on having adequate diverse trip signal ii I
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, SUMMAltY OF FACILITY ACTIVITIES Unit I was in cold shutdown at the beginning of this inspection period while repairs to a reactor coolant pump motor were completed. The unit was brought critical on November 1, following completion of this motor repair, and operated at 90% power from November 2 throughout the remainder of this inspection period. The utility operates Unit I at 90% power and makes periodic load reductions to accommodate lower system demand Unit 2 operated at full power through this inspection period without any significant operational event .0 PLANT OPEllATIONS (71707,93702) Operational Safety Verification Using applicable drawings and check-off lists, the inspectors independently verified safety system operability by performing control panel and field walkdowns of the following systems: low head safety injection, recirculation spray, and quench spray. These systems were properly aligned. The inspectors observed plant operation and verined that the plant was operated safely and in accordance with licensee procedures and regulatory requirement Regular tours were conducted of the following plant area.,:
- Control Room * Safeguard Areas
- Auxiliary Buildings * Service Buildings
- Switchgear Areas * Turbine Buildings
- Access C >ntrol Points e intake Structure
- Protected Areas * Yard Areas
- Spent Fuel Buildings * Containment Penetration Areas
- Diesel Generator Buildings * Unit 1 Containment Building During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures, facility configuration, and plant conditions. The inspectors verified adherence to approved procedures for ongoing activities observed. Shift turnovers were witnessed and staffing requirements conGrmed. The inspectors found that .
control room access was properly controlled and a professional atmosphere was maintaine Inspectors' comments or questions resulting from these reviews were resolved by licensee
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l l Control room instruments and plant computer indications were observed for correlation
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between channels and for conformance with technical speciGeation (TS) requirement Operability of engineered safety features, other safety related systems, and onsite and offsite power sources were verified. The inspectors observed various alarm conditions and confirmed that operator response was in accordance with plant operating procedure Compliance with TS and implementation of appropriate action statements for equipment out
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of service were inspected. Logs and records were reviewed to determine if entries were
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accurate and identiGed equipment status or deficiencies. These records included operating logs, turnover sheets, system safety tags, and the jumper and lifted lead book. The inspectors also examined the condition of various fire protection, meteorological, and seismic' i monitoring system Plant housekeeping controls were monitored, including control and storage of flammable ,
material and other potential safe hazards. The inspectors conducted detailed walkdowns of accessible areas of both Unit 1 ad Unit 2. Housekeeping at both units was acceptabl .2 Unit 1 Reactor Coolant INunp Failure At the beginning of the inspection period, the licensee had removed the faulted 'A' reactor coolant pump (RCP) motor from containment for shipment to Westinghouse. The RCP motor fault previously usulted in a reactor trip on October 9,1992 (see NRC inspection report 92-20). Visual inspection of the stator indicated that a localized turn to turn type insulation failure had occurred. Westinghouse performed a splice repair instead of a- *
complete motor rewind since the damage was localized in a top half coil. In parallel with the -
repair effort, the licensee explored the possibility of obtaining a spare motor from other nuclear facilities. Westinghouse completed the repairs and returned the stator to Beaver Valley on October 19. Westinghouse investigated the cause of the RCP failure but was unable to identify the most likely cause. Since the motor had been running for 317 ,
consecutive days, failure due to an incoming voltage surge was not likely. There was also no indication of thermal aging. Westinghouse concluded that the motor failure was a random event due to accelerated insulation aging caused by un' nown factor Following the reassembly of the RCP motor, the inspector reviewed the post-maintenance test run data. No deficiencies were noted as indicated by the A, B, and C phase current and the unbalanced current. The inspector observed the recovery of the 'A' reactor coolant system loop (refill, heatup, and opening of the loop isolation valves), mode changes, and -
startup operations. The inspector observed excellent operator performance, including strict procedural compliance, well disciplined command and control, and controlled operation of plant equipment. Additional senior reactor operators (SROs) assisted the on-shift nuclear shift supervisor in verifying that all prerequisites, such as maintenance. work request closeout, were satisfied. This in turn allowed the on-shift SROs to more fully concentrate on the operation of the plant. Overall, the .etartup activities were conducted in a safe and deliberate manne .3 Unit i Feedwater Transient On November 13, 1992, instrumentation and Controls (1 & C) technicians were performing a monthly surveillance on the Unit 1 'B' steam generator narrow range level indicator when a techt,ician error caused a feedwater transient. The maintenance aspects of this event are-discussed in Section 4.4. The technician had inadvertently removed the level control signal l
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for the 'A' steam generator which resulted n a full open demand signal to the ' A' feedwater
- control valve (FCV). At the time of the event, the plant was operating at 90% power, and the ' A' FCV was in automatic control with an open demand signal of about 50%. As indicated by the sequence of events recorder, annunciators in the control roam alarmed within three seconds of the error indicating 'A' steam generator level deviation ftom setpoint and abnormal 'A'_ feedwater flow greater than steam flow. The operator immediately recognized that feedwater flow was pegged high" on the indicator and that a full-open demand signal existed on the 'A' FCV. The operator immediately placed the 'A' FCV in manual control and reduced the open demand signal from the benchboard. Steam generator level had increased from 44% to 68% in about 30 seconds before the operator was able to restore level to within the programmed band. The inspector reviewed the sequence of events- _
recorder and steam generator level strip chart and noted that level was rapidly approaching-the trip setpoint of 75% and would have resulted in a feedwater isolation and turbine trip / reactor trip within several seconds. The inspector concluded that prompt and correct operator action averted the need for an automatic reactor trip and exemplified the excellent operator performance during this even .0 RADIOLOGICAL CONTROLS (71707)
Posting and control of radiation and high radiation areas were inspected. Radiation work permit c npliance and use of personnel monitoring devices were checked. Conditions of step-off pads, disposal of protective clothing, radiation control job coverage. area monito:
operability and calibration (portable and permanent), and personnel frisking were observed on a sampling basis. Licensee personnct were observed to be properly implementing their '
radiological protection progra .1 Spent Fuel Pool Cleanup
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The licensee has initiated a Unit I spent fuel pool cleanup project to remove non-fuel bearing '
irradiated waste components. These components include, for example, thimble plugs, burnable poison rod awemblies, and incore detectors. The project scope includes the identification and inver" iry of irradiated hardware, dose profiling, storage of components into a disposal container (liner), and disposal liner loading into a transportation cask for offsite burial. On October 22,1992, during the direct characterization of the waste, a Hi-Hi radiation alarm was received on the fuel bridge radiation monitor RM-207 (alarm setpoint:
15 mrem /hr). Two of the four portable area radiation monitors located within the work area -
also alarmed (alarm setpoint: 100 mrem /hr). The inspector reviewed this event to determine if the licensee's exposure controls were sufficient to have prevented an overexposure to the workers involve During the waste characteri7.ation process, the licensee used a gamma ray scanning device to determine the nuclide concentration of the irradiated hardware. Also, an underwater high radiation survey mstrument (RO-7) was used for radiation.do3e profiling. During this process. the irradiated hardware was grappled and moved underwater manually via a stainless
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4 l steel cable toward the RO-7 for dose rate measurements. As a general work practice, each hardware movement was monitored by a health physics technician During the incident o October 22, the work party leader regnested that the RO-7 underwater monitor be relocated from the crane twidge to the deep pit of the spent fuel pool in order to perform a survey'of a fuel bundle bottom support nozzle. However, this action was inadequately communicated as the instructions were misundeistood by a second supervisor. Instead, the worker was instructed to reposition the bottom nozzle to the RO-7 for the dose rate survey as per previous practice. The nozzle was initially about 10 feet under water. .The worker was aware that he was repositioning the nozzle and that a minimum depth of 6 feet of water should be maintained. As the nozzle was being repositioned, the worker attempted to -
maneuver the component around a second cable that was in the intended path of travel. At this time, radiation levels increased and two portable and the fuel bridge area radiation monitors alarmed. The worker's digital alarming dosimeter (DAD) also alarmed (alarm setpoint: 500 mrem /hr). The worker immediately recognized that the item he was positioning had caused the alarm and lowered the nozzle further into the pool. Area radiation levels returned to normai and were confirmed by follow-up survey The licensee conducted a dose assessment of the individuals involved. The worker's digital alarming dosimeter indicated that he uccived a whole body exposure of 5 mrem over the entire shift. He was, however, in a radiation field of 6.3 R/hr for about two seconds based -
on the dose and dose rate measured by the DAD. The worker's TLD indicated he received a whole body dose of 14 mrem between October I and October 22. The do'se rate from the nozzle assembly ranged between 6,000 - 9,000 R/hr on contact. The licensee estimated that the nozzle came within between 3.5 - 5.0 feet of the water surface. No other individuals mvolved received any measurable exposure during this inciden The licensee had established radiation protection controls to protect workers involved in this ,
project. The inspector reviewed NRC Information Notice 90 33, " Sources of Unexpectc Occupational Radiation Exposure at Spent Fuel Storage Pools," to determine if the licensee's controls were commensurate with those discussed in the notice. . Licensee controls included, in part: the establishment cf a hot-particle zone; measures to ensure that irradiated components are not left suspended under water from the pool handrail; measures to prevent radiation streaming; and the use of alarming portable area radiation monitors and personnel digital alarming dosimeters. The inspector also reviewed the licensee's basis for the RM-207 alarm setpoint of 15 mrem /hr. Calculations indicated that with six feet of water shielding and with the RM-207 one foot above the water surface, a component would have to read 88,000 R/hr on contact to set off the alarm. The licensee did nu anticipate handling any component with contact dose rates greater than 20,000 R/hr. The inspector concluded that -
the RM-207 setpoint was appropriate and conservative. Additwnally, the inspector concluded that the licensee's enhanced use of area radiation monitors and personal alarming-dosimeters as well as ALARA briefings prevented .he worker from receiving an excessiv exposure.
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NRC Information Notice 90-33 also states that measures shou!d be established to ensure that highly radioactive objects stored under water at one end of a line, whose other end is secured '
above the surface of the pool, are not unexpectedly pulled to the surface. Licensee procedure ITOP 9212. " Spent Fuel Pool Cleanup Project," states that irradiated components should be controlled to maintain a distance of six feet below the surface of the spent fuel pool. Even though the wrong nem was moved during this incideA as a result of misconununications, the worker was aware he was handling irradiated hardware. The inspector concluded that additional controls could have prevented the nonle assembly from 1 coming less than six feet from the water surface. For example, the nonle was repositioned ;~
without being directly monitored by a health physics (llP) specialist. At the time of the incident. the radiation protection supervisor was outside the spent fuel building assisting in the decontamination of an individual while the radiation technician was monitoring a separate l activity in the pwl Previous component movements were monitored as a general work practice, but not as a specific radiation work permit (RWP) requirement. The licensee has subsequently amended the RWP to read, "HP personnel shall be present to continuously ,
momtor dose rates at the water surface during movement of any item in or under water."
Additionally, the inspector noted that no visual references were available to provide indication of six feet of water d::pth. The refraction of light across the water surface can make it very difficuh for a worker to judge six feet of water unless a visual refetence or oepth marker is provided. The licensee has evaluated this comment and subsequently installed lanyards in the pool with a six foot marker attached. These measures now in place will provide additional defense in depth controls for worker protectio ,
The inspector concluded that this incident was of minor safety significance, but did have the potential to result in excessive exposure /overexposu.: to workers. Overall, the licensee's controls were adequate as they did limit the worker to wi ex vare of only 5 mrem durin the shift. However, the licensee's controls could hw beca wroved by having a radiation technician monitor each hardware movement per a.: r#P aqtnement us well as providing workers with a visual depth macke .0 MAINTENANCE AND SUlWEll, LANCE (62703,61726, sD Maintenance Observatinns The inspectors reviewed selected maintenance activities to assure that: the activity did not violate Technical Specification Limiting Conditions for Operation and that redundant components were operable; required approvals and releases had been obtained prior to commencing work; procedures used for the task were adequate and work was within the skills of the trade; activities were accomplished by qualified personnel; radiological and fire prevention controls were adequate and implemented; QC hold points were otablished where i required and observedt and equipment war 7toperly tested and returned to service. - ;
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hiaintenance activities reviewed included; j i
blWit 13826
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Iteplace seats on chemical addition ball valve 2QSS-249 MWit 04003 iteplace chips U3 through Ul1 on waste handling area detector 2RMJ- [
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M W it 13760 Install Design Change 1930 in Train ' A' Solid State Protection System (see Section 7.2)
l The inspector noted that the personnel involved with design change 1930 were
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knowledgeable, maintenance procedure quality was good, and the proper quality control
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oversight existed. The inspector also observed active participation by maintenance supervisor .2 Switchyard Mnintenance On November 16, 1992, the licensee initiated pre-planned maintenance acvities within the 138 kilovolt (KV) switchyard area. This maintenance required that one of the two offsite ,
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power supplies for each unit be deenergized for a short period. Technical Specification
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3.8.1.1.a requires that two physically independent circuits between the offsite transmission network and the onsite Class 1E distribution system be operable. The allowed outage time
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for this limiting condition for operation (LCO) is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Due to the safety significance of removing an offsite power supply from service for maintenance (I.e., LCO maintenance), the ,
inspector performed a review of the adequacy of the licensee's maintenance plan, safety precautions, and contingency plan The maintenance involved the replacement of the existing Z-30 line breaker, oil circuit breaker 0C1185, with an upgraded design equivalent breaker manufactured by Siemans
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Corporation. -The Z-30 line supplies the Unit 2 system station service transformer 2A via OCH 85 from either 138 KV bus 2 or the Midland Substation. The four system station service transformers supply each unit Class lE electrical system when the unit main-1 generator is off line. The existing breaker (OCil 85) will be used as a maintained spare for J
the other three offsite power supply breakers since the utility does not have a spare, and an exact replacement is no longer available from the original vendor. Due to the clearance .
points associated-with the breaker removal, installation, and testing, the licensee planned on three separate outages in which an offsite power supply would be removed from service. On two occasions, the Unit 2 transformer 2A would be out of service, and on one occasion, the- *
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Unit i transformer til would be out of service. The licensee has designated this maintenance activity an " Infrequently Performed Test and livolution," (IPTli) per Nuclear Group Administrative Procedure 8.23. The lirl'Il procedure provides guidance for the conduct of :
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the evolution, the degree of management involvement, and establishes management's expectations. The licensee does not routinely perform maintenance of this nature which .
results in voluntary entry into a LCO action statement. The Unit 2 Operations Manager was deQnated as the responsible test manage Prior to establishing the first Z-30 line clearance, the licensee verined the operability of the four station emergency diesel generators Gwo per unit) by performing the monthly full load suncillance tests. Also, prior to removing a unit system station service transformer from service, the licensee completed an engineered safety features (ESP) clearance checklist. This checklist is used to ensure that all redundant train components are available. During the periods in which an offsite power supply circuit was remavcd from service, the licensee restricted all maintenance on the opposite train to ensure equipment availabilit ,
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The inspector attended the prejob brie 0ng between lleaver Valley management and the Duquesne Light Company District Substation personnel. This brienng highlighted the day-to day job description, necessary coordination between Substation and lleaver Valley- -
personnel, and emergency actions to be taken in case of a unit trip while an offsite power supply is removed frem service. The licensee satisfactorily addressed the concerais raised by the insnector involving the switchyard maintenance. NitC Information Notice 9181,
"Switchyaid Problems that Contribute to Loss of Offsite Power," highlighted dif0culties associated with authority over the swiichyard under emergency conditions. At the Vermont Yankee nuclear facility, the restoration of offsite power was delayed because of lack of communications between the plant staff and switchyard personnel. The lleaver Valley IPTE project manager was designated as having authority over the switchyard during emergency conditions. A " traveling operator," with appropriate communications equipment, was assigned to the switchyard during the outage periods. The traveling operator acts as the focal point between Substatica and lleaver Valley personnel if lleaver Valley determines they need the Z-301ine or 138 KV bus 2 returned to service Communications would still be directed through the load dispatcher. Contingency plans were in place for restoring the Z-30 line or the 138 KV bus 2 to service. The licensee estimated that the maximum time for circuit restoration would be 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> if necessary. NitC Information Notice 92-13, " inadequate Control over Vehicular l'raffic at the Nuclear Power Plant Sites," informed licensees of continuing problemr. of vehicular traffic near safety systems resulting in loss of offsite power ever.ts. The inspector observed that the licensee had proper control of vehicles within the switchyaid. All non-designated work areas were roped off, and designed traffic lines were established; All vehicle backing operations were conducted with the assistance of spotter Positive control over the entry of vehicles and personnel into the switchyard was maintained by the license Overall, the inspector concluded that this maintenance resulted in a net safety benefit due to the improved reliability of the offsite transmission network. The maintenance was well
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planned as proper precautions, contingencies, and prerequisites were established prior to conunencing the line outage. Use of the IPTE process ensured an appropriate level of .
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management attention was focused on the successful completion of the job well within the outage time allowed by the limiting condition for operation. Excellent interface and coordination were demonstrated between the lleaver Volley and Substation personne .3 Surveillance Observatluns The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approsed procedures were in use, details were adequate, test instrumentation was properly ;
calibrated and used. Technical Specifications were satisfied, testing was performed by qualified personnel, and test results satisfied acceptance criteria or were properly dispositioned. The following operntional surveillance tests (OSTs) and temporary operating procedures (TOPS) were reviewed: .
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ITOP 91-06 Quench Spray Chemical injection Pumps (lQS 4A, B, C, D) Flow Rate Verification OST l.12C Safeguards Protection System Train 'B' Containment Isolation Phase B/ Spray Actuation Test OST 1.2 Steam Driven Auxiliary Feed Pump Test (lFW P-2)
OST 1.2 Motor Driven Auxiliary Feed Pumps (IFW-P-3A,311) Check Valves and Flow Test OST 2.1 Reeirculation Spray Pump 2RSS P21B Dry Test OST 2.3 Emergency Diesel Generator 2EOS EG2-1 Monthly Test ,
OST 2.3 Emergency Diese! Generator 2EGS-EG2-2 Monthly Test No significant problems were noteel during the conduct of these surveillances. These surveillances were properly controlled and documente .4 Technician Error 11uring Surveillance Testing During the performance of a monthly surveillance test on the Unit 1 'B' steam generator narrow range water level channel, a human error resulted in a transient on the feedwater system. However, prompt licensed operator action averted the need for an automatic reactor trip. The inspector reviewed this event and attended the licensee's critique to determine its safety significance and root caus <
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instrumentation and control technicians were performing Maintenance Surveillance Procedure !
(MSP)-24.06, "L-1 FW486 Loop 2 Narrow Itange Steam Generator Level Channel til Test." l
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This surveillance calibrates the level comparatus associated with the low-low level reactor trip / auxiliary feedwater start and the high level turbine trip /feedwater isolation signal, The feedwater control valve to the *ll'steoun generator (FCV-lFW-488) was placed in manual c"ntrol while the channel was in test. During the test equipment setup, a transmitter simulator was connected to test jack TJ-486 to allow the input of level test signals. The following procedural step instructed the technician to " place the signal injection test switch CT-486 in the up (test) position." llowever, the technician incorrectly placed the adjacent test witch, UT-476, in the test position.110th switches were correctly labeled. This error remosed the level control signal for the ' A'sicam generator. The steam generator water level control system automatically responded by demanding a full-open signal to the 'A'
FCV. The technician recognized his error when he was unable to adjust the transmitter l simulator. The technician subsequently restored test switch CT-476 to its normal position in about 30 seconds. Prompt action by the licensed reactor operator in the control room prevented steam generator level from reaching the turbine trip /feedwater isolation signal setpoint of 75E :
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The inspector reviewed the procedure and noted that no procedural deficiencies existe Specifically. the format was consistent with the standard procedure upgrade format, the instructions were clear, equipment identification was correct, and the procedural step in question contained only one action. The inspector also observed the interior of the protection rack and concluded that the error Jid not result from poor human factors engineering such as poor man-machine interface (labeling deficiencies, equipment arrangement), or poor work environment. The inspector agreed with the licensee's conclusion that human' error was the cause of incorrectly following the procedure and that proper self checking, as per recent training, could have prevented the error. Overall, this event had minor safety significance as operator action averted the need for a reactor protection system actuatio .0 SECUl(ITY (71707) ;
implementation of the physical security plan was observed in various plant areas with regard to the following: protected area and vital area barriers were well maintained and not compromised; isolation zones were clear; personnel and vehicles entering and packages being delivered to the protected area were properly searched arid access control was in accordance
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with approsed licensee procedures; persons granted access to the site were badged to indicate whether they have unescorted access or escorted euthorization; security access controls to vital areas were maintained and persons in vital areas were authorized; security posts were adequately staffed and equipped, security personnel were alert and knowledgeable regarding ,
position requirementsc and that written procedures were available; and adequate illumination was maintained. Licensee personnel were observed to be properly implementing and following the Physic.'l Security Pla ,
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As described m previous N14C inspection reports 92 20/20 and 92-21/21, a contract to provide the site security force was awarded to llurns international Security Services on September 30,1992. Ilurns replaces Security llureau, Incorporated. Transition to llurns international was completed during this inspection perial. The guard force and supervisors were largely unchanged by the change in contractors because all active Security llureau, incorporated guards and supervisors were offered employment with Ilurns international _ The transition was, therefore, mainly administrative. The transition went smoothly. The I I
excellent performance of the security force continued and appeared unaffected by the new contrac l ENGINEEltlNG AND TECilNICAl, SUPPol(T (2515/94,37828,7?707)
! (Closed) PWit Moderator Dihition Tl 2515/94 i Previous licensee and NRC assessments concluded that no additional licensee actions were required with regard to the moderator dilution issue. The previous NRC project manager's review of this issue dated May 12, 1988, concluded that there were na paths whereby a '
boron dilution event could occur, other than those already analyicd in the Unit I and 2 Final- ;
Safety Analysis Reports and that the concerns of Ti 2515/94 did not apply to this site. The inspector verified with the current NRC pre!cci manager that the previous project manager's '
assessment in this area was still acceptable. This item is close .2 Unit i Pinnt Computer lleplacement l
l On November 6,1992, the licensee implemented a design change to replace the Unit i P-250 in-plant computer. The P 250 is a 1968 vintage computer used for process monitoring. The new computer has numerous advantages over the P 250. Improvements include: extensive I
use of on line system diagrams with associated temperature, pressure, and How parameters; j expansion capability; improved data scan frequency; human factors engineering for operator l interface; visual data trending; and programmed surveillance capabilities such as continuous thermal power monitor. The computer repiacement was being performed while the unit was i l
operating at 90% power. The inspector reviewed the design ch,,nge package (DCP 1812) to
- ensure that the impact on plant operations was sufficiently evaluated by the license .
The data obtained from the P 250 is used for several operational surveillance tests. These include, for example, reactor coolant system leak rate calculations and daily heat balance
, calculations. -Prior to removing the P-250 from service, the licensee established an alternate l
means of data collection for interim monitoring (temporary modification 192-12). A data logger (Chessell 4200 proecssing recorder) was placed in service and calibrated for the points
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to be monitored. The inspector reviewed the applicable surveillance procedures to ensure that all computer points needed for-the surveillances were available on the data logger. The
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mspector also compared the parameters logged by both the P-250 and the Chessell for accuracy. The final surveillance calculations were also compared based on the two sources
! of data. The required computer points and calibrations were previously verilled by licensee i
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computer engineers and senior reactor operators. No discrepancies were noted by the inspector. The licensee established a 31-day window for completing the design change. This ;
was due to the use of the P 250 for several technical speci0 cation surveillance requirements
that are performed every 31 effective full power days. These tests include flux mapping, delta Aux target update, and critical boron concentration. The licensee completed these tests prior to removing the P 250 from service. The licensee also established alternate monitoring
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of these pcints to be used if neede The licensee also evaluated the impact the computer replacement would have on other instrumentation. The replacement project did not affect either the availability or operation of the sequence of events recorder, the inadequate core cooling monitor (ICCM), or the plant variable computer (PVC). The PVC monitors plant data to permit the assessment of plant conditions, including accident monitoring. The impact on the safety parameter display i system was minima! and only involved core exit thermocouple information for one minute during a power supply transfer. Thermocouple date was still available on the ICCM during j this time. Two alarm functions, axial flux difference and rod deviation, were provided by i
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the P 250. However, due to previous program problems with the P-250, these functions were already being logged by han '
The inspector concluded that the installation of the new computer represents a significant management commitment toward upgrading existing plant equipment and improving -
plant / operator performance. The design change package and associated safety evaluation were thorough and detailed. The early involvement of licensed operators in the development-and implementation of this project significantly contributed to minimizing the impact of the -;
computer replacement on plant operations, Problems which could occur from removing the P 250 from service while at power were properly identined, evalur.ted, and resolved by the license .3 Annual Fire Drill On October 15, 1992, the inspector observed the 1992 annual fire drill. Nuclear Group Administralise Procedure 3.5, " Fire Protection," requires that a site Orc drill be conducted-with local Ore department participation. The local volunteer fire departments consisted of companies from Midland, Hookstown, Shippingport, Raccoon, and Industry. The inspector observed a good turnout from these organizations and a high level of participatio The inspector noted several deficiencies that were the result of overall drill coordination by the drill controllers. For example, the volunteer fire departments were all dispatched to the site by the Beaver County Emergency Management Agency before the Ore drill began. The Ore departments arrived on site before they were ever requested by the nuclear shift sujuvisor. This indicates that a more thorough pre-drill bric0ng of the offsite agencies ma be warranted in the future. The inspector does recognize that this did not have a major effect on the drill, as the fire departments were held at the staging area until they were needed. Another drill coordination de0ciency was the failure of chemistry department
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t personnel to participate in the drill. Chemistry department personnel, along with operations l personnel, are designated as fire brigade members. Although the minimum number (five) of fire brigade personnel was available and did participate in tne drill, provisions should have been made for the shift chemist to participate. The inspector acknowledges that the on shift chemist during the drill had other duties to fulfillt however, the chemistry department ,
manager was never contacted by the drill coordinators to provide an extra chemist for drill participation. Another drill coordination problem was evident when the offsite hazardous material (llAZMAT) response team was kept at the staging arei One of the drill objectives was to test the facility response to a hazardous material spill. Although this objective was satis 0ed by the licensee's onsite liAZMAT team, drill coordinators did not ensure that the '
bcensee personnel had an oppottunity to interact with the offsite llAZMAT tea Another concern of the inspectors was that fire brigade members were not initially afforded the opportunity to voice their own comments and to provide feedback to the responsible fire protection engineers- The offsite post-drill critique did not iriclude members of the licensee's -
fire brigade. Additionally, the Gre brigade was unable to conduct their own debrienng due
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to technical specification overtime considerations. One of the fire brigade's responsibilities is to cooperate with the offsite volunteer Ore departments in a coordinated fire fighting rol I; ire brigade members did inform the inspector that they were unsure of their role in c mteracting with the offsite departments. Communication problems between the Gre brigade
- and offsite Gre departments were identified by drill controllers and were a drill dencienc The fire brigade chief did subsequently document and submit his own comments for es atuano Overall; these examples indicate a general weakness in regard to drill preparation and coar6 nation by the licensee. The inspector discussed these concerns with the lleensee management and was informed that future Hrc drills will involve a greater degree of participation and coordination by emergency planning specialists. The inspector is satisGed with this action to enhance drill quality as the emergency planning specialists have greater expertise in the planning and conduct of drills. Additionally, the inspector was informed that operations management would have a greater degree of oversight in Gre brigade training and drilling so that fire brigade members are afforded the opportunity to voice their own comments for evaluatio .0 SAFETY ASSESSMENT AND QUAL.lTY YEltlFICATION (40500,71707, 90712, 91700) Review of Written Reports The inspectors reviewed Licensee Event Reports (LERs) and other reports submitted to the NRC to verify that the details of the events were clearly reported, includ.ing accuracy of the description of cause and adequacy of corrective action. The inspectors determined whether further information was required from the licensee, whether generic implications were
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indicated, and whether the event warranted further onsite fellow up. The following LER was reviewed:
thud 92-08 incomplete Containment Hydrogen Analyzer Surveillance as a Result of inadequate Change implementatio This event is discussed in NRC inspection report 92-2 The above LER was reviewed with respect to the requirements of 10 CFR 50.73 and the _
guidance provided in NUREG 1022. Generally, the LER was found to be of high quality with g(xxi docunientation of event analyses, root cause determinations, and corrective acuon ,2 Unqualllied Reactor Coolant Pump Undervolinge Relays On October 2,1992, the licensee concluded ! hat the reactor coolant pump (RCP) bus undervoltage relays, which start the Unit I steam driven auxiliary feedwater (AFW) pump
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during a small break LOCA, could not be relied upon because they were not Class lE. The relays were still capable of functioning. This was reported on October 21,1992, by an Emergency Notification System (ENS) call. Further review by the licensee determined that Unit 2 has a similar design. The ENS call was updated to include Unit 2. The licensee is preparing an 1.ER on this even '
Unit I was in cold shutdown when the unqualified RCP undervoltage relays were discovere To correct the design deficiency at Unit 1, the licensee implemented a design change to
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provide an automatic start of the steam driven auxiliary feedwater pump upon receipt of a safety injection (SI) signal. Design change 1930 wired a Class IE SI signal slave relay output (Train ' A' and 'B') into_ the start circuit for the AFW pump. The design change was completed prior to the plant exiting cold shutdown conditions. The start of the steam driven AFW pump is now consistent with the Westinghouse small break LOCA analysis. The licensee satisfactorily performed operational surveillance test 1.7.11, "CHS and SIS Operability Test." which tested the opening of steam supply valves (TV lMS 105A and B)
upon receipt of the Si signa A nnxiification of the Unit 2 steam driven AFW start circuit similar to that performed on Unit 1 is planned for the next outage. The basis for continued operation (BCO) of Unit 2 until that modilication is completed was prepared by the licensee. Essentially, the basis is that other start signals (primarily low-low steam generator level) are available that will start
< the steam driven AFW pump. The inspector discussed this BCO with the NRC project manager and Region 1. The BCO provided an adequate basis for continued operatio _ ~ _ _ _ . - _ _ __ _ _ _ _ _ _ . . . _ _ _ _
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This AFW start signal issue was identified by the licensee while preparing a safety evaluation to support increased steam generator tube plugging. This shows that the licensee did a ,
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thorough review of accident analysis assumptions during the preparation of that assessmen The same non lli RCP bus undersoltage relays that provide this AFW start signal also 3 provide the input to the RCP bus undervoltage reactor trip signal. The licensee had reviewed the use of these relays for this reactor protection system function in 1991 in response to
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Information Notice 91-11. The licensee concluded that both the RCP bus undervoltag:: and
underfrequency relays should have been designed for Class 111 application. However, the purpose of these trips is to protect the core from loss of forced flow and three additional protection functions provide adequate diversity in protection for the complete loss of RCS flow transient. These diverse trips are loss of RCS loop flow, RCS k>op overtemperature, and RCP breaker open. These three diverse trips are from III relays. The issue of using non lii relays was previously reviewed in NRC inspections 334/81-28,82-06, and 82-08 and -
found acceptable. The inspector discussed this issue with the NRC project manager and Region I an(1 contirmed that adequate loss of flow protection is provided by these diverse trip signal .0 EXIT $1EETING AND NRC STAFF ACTIYlTIES Preliminary inspection Findings Exit At periodic intervals during this inspection, meetings were held with senior plant ;
management to discuss licensee activities and inspector areas of concern. Following conclusion of the report period, the resident inspector staff conducted an exit meeting on November 25, 1992, with Heaver Valley management summarizing inspection activity and findings for this perio .2 Attendance at Exit Meetings Conducted by Region-llased Inspectors During this inspection period, the inspectors attended the following exit meetings:
Inspection Reporting ,
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12ain hihisci Repnr.LMot insnector :
10/23/92 Confirmatory Chemical and 92 23/23 J. Kottan c Radchem Measurements 10/30/92 Procedurally Induced LOOPS 92-25/25 J. Beall
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15 NRC Sinfr Activities inspections were conducted on both nonnat and backshift hours: 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> of direct inspection were conducted on backshift; 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> were conducted on deep backshift The times of backshift hours were adjustert weekly to assure randomnes R. Janati Nuclear Engineer. Pennsylvania Department of Environmental R'esources (DER)
visited the site and inspectors on October 20. October 22, and November 16 and discussed inspection activities and the licensee's performanc _
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