IR 05000334/1987005
| ML20205T505 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 03/31/1987 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205T486 | List: |
| References | |
| 50-334-87-05, 50-334-87-5, NUDOCS 8704070311 | |
| Download: ML20205T505 (18) | |
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U. S. NUCLEAR REGULATORY' COMMISSION
REGION I
Report No.
50-334/87-05 Docket No.
50-334 Licensee:
Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279 Facility Name: Beaver Valley Power Station, Unit 1 Location:
Shippingport, Pennsylvania Dates:
February 1 - March 15,1987 Inspectors:
W. M. Troskoski, Senior Resident Inspector L
J. P 'vidy, Resident Inspector, cVPS Unit 2 Approved by: #. h. h[
Y/N/87 7.. E. Tr*i p, Chief, Reactor Projects Section 3A
' Date
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Inspection Summary: Inspection No. 50-334/87-05 on February 1 - March 15, 1987 Areas Inspected:
Routine inspections by the resident inspectors (115 hours0.00133 days <br />0.0319 hours <br />1.901455e-4 weeks <br />4.37575e-5 months <br />) of licensee actions on previous inspection findings, plant operations, housekeeping, fire protection, radiological controls, physical security, BOP maintenance activi-ties, fifth refueling outage cable installation, the licensed operator retraining program, Licensee Event Reports, administrative practices of the Onsite Safety Committee (OSC) and Maintenance and Operations Subcommittee (MOS), chlorine de-tection system, status of the hydrogen recombiners, TMI Action Items Update, and compatability of dual unit commitments.
Results: One violation was identified (failure to follow plant configuration con-trol procedures, detail 4.b.3).
One concern relates to the length of time needed to resolve the hydrogen recombiner isolation valve issue was elevated to senior management attention (detail 13).
8704070311 870331 PDR ADOCK 05000334-G PDR
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TABLE OF CONTENTS Page 1.
Persons Contacted....................................................
2.
Plant Status.........................................................
3.
Followup on Outstanding Items................
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4.
Plant Operations.....................................................
a.
Genera 1.........................................................
b.
Operations......................................................
c.
Plant Security / Physical Protection............................
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d.
Radiation Controls..............................................
e.
Plant Housekeeping and Fire Protection..........................
5.
Licensed Open tor Retraining Program.................................
.3.
Inoffice Review of LERs..............................................
7.
Onsite Safety Committae............................................
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8.
MOS Review o f Incident Reports..............................
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9.
Fifth Refueling Outage Cable Insta11ation............................
10.
B0P Maintenance......................................................
11.
TMI Action Item Update...............................................
12.
Chlorine Detection System............................................
13.
Hydrogen Recombiners........................
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14.
Compatability of Dual Unit Commitments...............
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15.
Exit Interview.......................................................
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DETAILS 1.
Persons Contacted During the report period, interviews and discussions were conducted with mem-bers of licensee management and staff as necessary to support inspection activities.
2.
Plant Status The reactor operated at full power during this inspection period, with the exception of one reactor trip on February 7, 1987, due to a malfunction in the turbine overspeed control system (see detail 4.b.1).
Major maintenance activities included overhaul of the A river water pump, work on the steam generator atmospheric dump valves and both fire pumps (see detail 5). NRC Commissioner Carr toured both units and met with senior DLC management on March 10-11, 1987.
At the concl sion of this inspection period, the licensee was initiating plans for a mid-cycle outage beginning in late April and expected to last about 20 days. The primary purpose will be the removal of the wall separating the Unit 1 and 2 control rooms.
3.
Followup on Outstanding Items The NRC Outstanding Items (01) List was reviewed with cognizant licensee per-sonnel.
Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field inspec-tion to determine whether licensee actions specified in the OIs had been satisfactorily completed.
The overall status of previously identified in-spection findings were reviewed, and planned and completed licensee actions were discussed for those items reported below:
(Closed) IFI (84-21-01 thru 11): Post-Accident Sampling System.
The original NRC team inspection of the post-accident sampling system identified certain activities that required improvement to be acceptable relative to NUREG 0737.
DLC responded to those concerns in letters dated December 6, 1984 and February 28, 1985.
Inspector discussions with Regional specialists indicated that a second team inspection will be scheduled to evaluate each of the 11 individual items, technically, as NRC resources permit.
For administrative tracking pur-poses, the verification of licensee improvements relative to the PASS NUREG 0737 requirements is URI (87-05-01).
(Closed) Unresolved Item (86-29-02): Review corrective actions regarding operability of opposite train EDG when performing relay testing.
The various relay calibration procedures (MSPs) were reviawed to require shift supervisor notification of any problems identified within the first 20 minutes of relay l
testing to allow time to perform the action specified in TS 3.8.1.1.
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tionally, the inspector verified that the opposite train EDG has now been l
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scheduled for monthly testing on the shift prior to performing the undervolt-age and degraded voltage test; as was observed on February 4, 1987.
This item is closed.
(Closed) IFI (86-27-01 thru 12): Evaluate licensee corrective action for 12 individual EPP drill items.
Some o' these items had been identified by the licensee during a self-critique of 'he exercise and others by the NRC team.
These items covered a range of subjscts from updating work sheets, wall maps, PASS procedures and other items which did not have a significant impact on the drill.
Since each area receives routine NRC attention during the station's annual exercise, these 12 items are being administratively consolidated into IFI (86-27-01): Followup on 12 Improvement Actions listed in Detail 3, Exer-cise Observations, for the November 1986 Drill.
(Closed) Unresolved Item (84-28-01): Nonconformance in general stores ware-house area.
Unqualified Fisher-Porter pressure transmitters were identified as being maintained in the storeroom as qualified spares awaiting disposition by Engineering.
These particular transmitters were to be replaced with new Barton models per DCP 351.
By memo dated February 25, 1985, NED deleted the Fisher-Porter transmitters from the qualified list and initiated the appro-priate requat to stock qualified Barton components as spares.
This item is closed.
(Closed) Unresolved Item (84-25-05): Review QC program change and verify resolution of nonconformance reports prior to startup.
This item was last reviewed in Inspection Report 334/85-02 and left open pending program changes to ensure all QC work at BVPS-1 (whether performed by 0QC or a contractor's QC) would be performed to the same program controls.
The Schneider Power Corporation QC Procedure QCP 15.1, effective March 29, 1985, was amended to address this concern.
Specifically, QC Engineering prepares a bi-weekly status of nonconformance reports which are currently open.
That status report now provides a tracking mechanism which is reviewed by DLC QC management, and adequately addresses the inspector's concern.
This item is closed.
(Closed) IFI (84-25-06): Determine cause of the auto bus transfer failure as reported in LER 84-12.
Investigation revealed that breaker 141A did not open on undervoltage because the undervoltage transfer scheme was cut out as part of a test to load Unit 2's transformer via Unit 1 electrical loads.
The cround overcurrent relay on Unit 2 4KV bus 2A feeder breaker 42A tripped causing the breaker to open which de-energized Unit 1 4KV bus 1B.
Relay testing of the ground overcurrent relay determined that it had tripped due to two deficiencies.
First, a shorting switch blade / jaw interface was not making good contact and allowed establishment of a parallel path to ground through the impedance of the shorting switch contact and the overcurrent re-lays.
The second problem was due to the physical location of the ground cir-cuit which allowed the current resulting from that parallel path to flow through the ground overcurrent relay.
Unit 2 has since taken appropriate corrective actions to their relay scheme.
No malfunction occurred on Unit 1 components and this item is closed.
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4.
Plant Operations a.
General Inspection tours of accessible plant areas were conducted during both day and night shifts with respect to Technical Specification (TS) com-pliance, housekeeping and cleanliness, fire protection, radiation control, physical security and plant protection, operational and maintenance administrative controls.
b.
Operations During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures, facility configuration and plant conditions.
The inspector verified adherence to approved procedures for ongoing activities observed.
Shift turnovers were witnessed and staffing requirements confirmed.
Except where noted below, the inspector comments or questions resulting from these daily reviews were acceptably resolved by licensee personnel.
(1) A reactor trip occurred from full power at 2:10 am on February 7, 1987, due to a low-low level in the C steam generator.
The initi-ating event was a malfunction in the EH system whereby an erroneous overspeed condition was sensed (normal setpoint is 103%), leading to the auto closure of the turbine governor and intercept valves.
The subsequent SG level shrink was due to (1) steam generatcr pres-sure increase resulting from governor valve clost re and (2) an in-crease in colder feedwater flow to compensate for the level loss.
Because the rod control system was in manual, the primary system could not match the secondary system load reduction and a PORV lifted for about 1.4 seconds to limit RCS pressure to 2335 psig.
After the reactor was stabilized, it was noted that all shutdown and control rod banks were reading approximately 25 steps on the analog rod position indicators (RPIs), with all of the rod bottom lights lit.
Subsequent licensee investigation determined that three of the four RPI power supplies were out of specification, resulting in system operation with degraded voltage output.
The power sup-plies are divided into two sets which are auctioneered to assure proper RPI operations should any one power supply or group totally fail.
The length of time that the first power supplies failed is unknown.
New power supplies were obtained from the w rehouse and the scrapped Unit 2 analog system and were insts? led to return the RPI system to normal. The acting Plant Manager informed the inspec-tor that a monthly surveillance check of these power supplies would be developed.
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During recovery, the inspector observed portions of OST 1.2.1, Power Range Monitor (PRM) Test, in progress.
This surveillance test was being performed per an OMCN to 0M 1.50.4J, Station Startup - Re-covery From Reactor Trip, in accordance with corrective actions for Violation (87-02-01).
No concerns were identified.
(2) Through a review of control room logs, the inspector fcund that there was an excessive amount of instrument air used on February 13, 1987.
Licensee investigation determined that the unusual demand was from an air powered blower used to cool a local area in the main steam valve room where I&C technicians had been working on the C steam generator atmospheric dump valve.
The inspector discussed this with the Operations and I&C Supervisors and was in.Srmed that the air oiiven blowers would be removed from the station and only motor driven blowers allowed. The inspector had no further concerns.
(3) A minor radioactive gas release occurred in the PAB while returning the A degassifier (BR-C-2A) to service on February 13, 1987.
Both the PAB ventilation vent gaseous rad monitor (RM-VS-1018) and the gaseous waste disposal blower rad monitor (RM-GW-108B) reached a maximum reading of 240 cpm, for 45 and 20 minutes respectively.
The slightly elevated levels resulted in the control room receiving high rad alarms.
No high-high rad alarms were triggered that would have initiated automatic HVAC actions.
The inspector reviewed the abnormal gas release record No. 0832 in-itiated by the station to calculate and document the release.
The total activity monitored by RM-GW-108B indicated that about 6.4E4 micro curies were released which equates to a maximum permissible concentration (MPC) of less than 7E-7 at the site boundary when averaged over a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.
The PAB ventilation monitor, RM-VS-101B, tracked a 7.2 E6 micro curie release which resulted in a MPC of about 4.7 E-3 at the site boundary.
These numbers are well with-in the established limits set forth in 10 CFR 20, Appendix B and were about 2% of the limits identified in 10 CFR 50, Appendix I.
The source of the gas was the gaseous waste surge tank that was vented into the PAB through several open vent and drain valves.
This release occurred due to a combination of operator error and inadequate procedure use as discussed below.
A chronology of the events is as follows.
In preparation for re-turning the A degassifier to service, the 4-12 shift on February 13, 1987, began implementing equipnent clearance No. 525200.
The station wanted to align the degassifier such that a chemistry sample of the gaseous contents could be obtained to determine whether or not the system would have to be purged of oxygen.
The alignment was to be performed under TOP 84-21 and OM Procedure 1.8.4GG, Purg-ing Degassifiers.
About one-half of the clearance had been imple-mented prior to shift change, and at least one more shift would be
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required to complete the work.
Operations personnel were under the assumption that OM Procedure 1.8.4GG was only setting up the degas-sifier for sample and purging when in actuality it was setting up normal system alignment.
After shift turnover, the 12-8 shift noted that the gaseous waste surge tank pressure had dropped from about 18 to 0 psig and that the oxygen analyzers were up scale.
Investigation found GW-156, the oxygen analyzer return line isolation valve open when it should have been shut.
This valve was not on the equipment clearance list.
Because of past operating experience with backleakage into the de-gassifier through the discharge check valves, a check of the degas-sifier inlet isolation valve (GW-1) was performed.
It was also found open and subsequently reclosed.
Despite finding these two valves out-of position, the gaseous waste surge tank was repressur-ized with nitrogen without completing a system walkdown to verify that the remainder of the system was correctly aligned.
The re-pressurization resulted in blowing the radioactive gas from the lines out into the PAB through various vent and drain lines that were also mispositioned.
This resulted in the receipt of the rad monitor alarms in the control room and termination of the evolution.
Subseqent licensee investigation indicated that the valve status prints had not been properly updated, nor the standard practice of checking all valves within a clearance boundary adhered to until after the release occurred.
No reason could be identified as to why GW-156 or GW-1 were opened.
The failure to perform a walkdown of the system during the fill and vent operation to ensure system integrity, the replacement of caps and flanges, and to post clear-ance tags on vent and drain valves of radioactive systems left open and unattended is a violation (87-05-02) of OM Chapter 1.48.6B, Mechanical and Electr#.a1 Clearance Procedures.
(4) Motor driven auxiliary feedwater pump FW-P-3A was unintentionally started on February 27, 1987.
Operations personnel were in the process of placing the steam driven auxiliary feedwater pump (FW-P-2) on clearance for an oil change when the A train auto start signal was initiated.
The cause of the event was inadequate opera-tor consideration of the auto start signals affecting the auxiliary feedwater system. The clearance of FW-P-2 included removing motive power (steam) from the Terry Turbine by closing the isolation valve MS-105.
However, this steam header branches off into two parallel lines, each with an air to close, fail-open isolation valve (MS-105A and B) to provide ESF train redundancy.
The mechanics realized that any air system failure would allow MS-105 A and B to open, releasing trapped steam upstream and requested Operations to bleed off the pressure.
The operators did this by opening MS-105A from the con-trol room bench board which provides an input into the A train logic system that an auto start of FW-P-2 is required, and in coincidence
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with the low pressure on the pump discharge side 10 seconds later, initiated an auto start of FW-P-3A to compensate for a start failure of FW-P-2.
As soon as the pump started, the control room operator placed the control switch in the after-stop position until MS-105A could be reclosed.
Appropriate ENS notifications were made.
Though this
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event has no hardware safety significance, it does highlight opera-tor inattention to detail when performing clearance work on an ESF component. No formal procedure existed for this evolution and the acting Plant Manager informed the inspector that one would be de-veloped.
Operator training was judged to be adequate.
(5) During the February 4, 1987, run of emergency diesel generator (EDG)
No. 2, the fuel oil filter delta-P indicated about 46 psig.
The normal range for this parameter is 24 to 45 psig, as specified in the monthly surveillance test, and an MWR was written by the Opera-tions staff to change the fuel filters.
As another facility recently experienced problems with clogged fuel filters from fiber materials that were introduced during fuel tank cleaning, the inspector observed the work in progress.
No visual clogging of the fuel filters was apparent and no foreign material was evident.
While the No. 2 EDG was out of service, the inspector periodically verified compliance with_the TS action statement which requires the No. 1 diesel to be started once every eight hours.
After maintenance, the inspector observed the return to service test on March 3, 1987. The diesel was successfully started but had to be manually stopped within several seconds by the local operators because the fuel filters were spraying oil.
Several other attempts were unsuccessful until licensee personnel realized that the fuel line was interfering with the filter alignment, which resulted in pinching the gasket.
After correct installation, the diesel was satisfactorily tested.
c.
Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in various plant areas regard to the following:
Protected area barriers were not degraded;
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Isolation zones were clear;
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Persons and packages were checked prior to allowing entry into the Protected Area;
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Vehicles were properly searched and vehicle access to the Protected
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Area was in accordance with approved procedures;
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Security access i..;rols to Vital Areas were being maintained and
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that persons in Vital Areas were properly authorized.
Security posts were adequately staffed and equipped, security per-
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sonnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and Adequate lighting was maintained.
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Within this scope, no concerns were identified.
d.
Radiation Controls l
Radiation controls, including posting of radiation areas, the conditions of step-off pads, disposal of protective clothing, completion of Radi-ation Work Permits, compliance with the conditions of the Radiation Work Permits, personnel monitoring devices being worn, cleanliness of work areas, radiation control job coverage, area monitor operability (portable and permanent), area monitor calibration and personnel frisking proce-dures were observed on a sampling basis.
No discrepancies were identified.
e.
Plant Housekeeping and Fire Protection Plant housekeeping conditions including general cleanliness conditions and control of material to prevent fire hazards were observed in various areas during plant tours.
Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observed.
Both the motor and turbine driven fire pumps were rendered inoperable for about one hour on March 5, 1987.
The motor driven pump (FP-P-1) had been previously removed from service due to an inoperable pressure switch that would auto start the pump on low pressure, and a leaking check valve.
During a shift tour of the intake structure, an operator noted that the diesel driven fire pump (FP-P-2) was cycling on and off repeatedly.
The pump was manually shut down to prevent possible equipment damage.
The licensee brought the condition immediately to the attention of the in-spector and initiated repairs to FP-P-1.
The motor driven pump was started and left on minimum flow, nullifying the function of the pressure switch.
Followup on cause of the diesel driven fire pump cycling indi-cated that the batteries had drained down and were not strong enough to crank up the diesel.
At the conclusion of thk inspection period, both pumps had been repaired and returned to service, and the station sub-mitted the special report required by TS 3.7.1.4.1 on March 5, 198..
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The root cause of the problem appears to be scale buildup ca the 1.5 inch hydropneumatic tank line.
System leakage is enough that the tank cannot maintain adequate pressure, resulting in FP-P-1 cycling for brief periods.
When out of service, FP-P-2 is started (setpoint is about 10 psig higher),
but not run long enough to adequately recharge the batteries.
At the conclusion of this inspection, the station had flushed the line and i
issued operating instructions to run FP-P-2 at least 30 minutes each time it is started to ensure an adequate battery charge.
The adequacy of long term corrective action for the hydro line will receive routine inspector review.
5.
Licensed Operator Retraining Program 10 CFR 55, Appendix A, requires that each facility licensee provide a requali-fication training program for their licensed operators.
This inspection was conducted by a Region-based license examiner to determine whether the re-training program is effectively providing training and evaluation of both site specific and industry wide events.
BV-1 provides this required training in two one year cycles, each consisting of six four day modules.
One day of each session covers general site training such as first aid, fire brigade, EPP, as well as a plant status update lecture and other operator-specific non-technical issues.
The remaining time is de-voted to licensed operator retraining (LRT), which focuses on both systems and procedures.
Written quizzes are provided to test the operator's retention of the learning objectives emphasized during the lectures.
The plant status update lesson plan was reviewed for various modules of the 1986 thru 1987 cycle and compared to the reference material submitted by INP0 and the BV station.
Though the written objectives focused operator attention on important aspects of the specific events, it did not specifically f aentify how the lessons learned could be used to improve day-to-day station operations.
Additionally, the objectives were not written to stand alone as they often built upon previous objectives.
The lesson plans as written covered the necessary information to allow the operator's to be able to accomplish the individual objectives.
They were concise, clear and well-written.
The over-all aspect of this area was judged to be satisfactory.
The weekly quizzes for several modules were reviewed to ensure that an ade-quate sampling of objectives were covered during the plant status update lec-ture.
The inspector found that five of the six events covered were addressed by at least one question during at least one session's weekly quiz.
The inspector noted that no methodology had been developed to prioritize the events included in the plant status lecture.
For example, the feedwater line break at Surry, a sister plant, is not scheduled to be covered in the upcoming plant status update lecture.
Discussions with the Training Supervisor indi-cated that the specifics of this event had already been prcvided to the l
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operators in an informal way and that, as its total effect on the plant was no more than a feedwater line break which had already been covered, no further review was planned.
The inspector found that the volume of information required for operator reading is extreme and that coordination between Operations and Training is needed to alleviate this concern.
There appears to be no prioritization of incoming events to filter out those items that are not applicable to Beaver Valley.
These comments were acknowledged by the station and the inspector was informed that the Operations Department is already implementing steps to more closely monitor the reading material required by operators.
Instructor qualifications were also reviewed.
All but one instructor was either certified by the NRC or SR0 licensed.
The instructor in question was certified by Westinghouse under an agreement between the NRC and Westinghouse.
The details of this agreement, along with a copy of the instructor's certifi-cate, was subsequently provided to the Region by the licensee.
The inspector also interviewed selected R0 and SR0s to determine their opinions on the LRT.
The general consensus was that the program evolution has been satisfactory and that the lecture and simulator training covered all aspects of their jobs. They did note that better coordination between the lecture and simulator training would be desirable.
Administrative controls are in place for the conduct and tracking of the LRT and were found to be effective.
The Training Department uses unwritten poli-cies to regulate much of the conduct of licensed retraining. A review of attendance records from Modules 1, 2, and 3 indicated that operators were attending the required lectures and that they were not given the modules quiz until all lectures were attended.
Although the licensee's policy in this regard is not formally specified'in the Training Department's administrative procedures, the inspector found the licensee's practice to be acceptable.
In conclusion, the LRT Program was found to be conducted in a satisfactory manner.
6.
In-Office Review of Licensee Event Reports (LERs)
The inspector reviewed LERs submitted to the NRC Region I Office to verify that the details of the event are clearly reported, including the accuracy of the description of cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup.
The following LERs were reviewed:
LER 86-05-02: Update on Inoperable Filter Bank Sprinkler Nozzles During the fifth refueling outage, a significant portion of the main charcoal filter bank fire suppression nozzles were found blocked and not able to per-form their safety function. This was identified during performance of BVT
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1.1-1.33.1 which verifies operability of these nozzles once per 36 months.
Because of the numerous problems identified with the A filter bank nozzles, expanded testing confirmed a similar problem with the B bank.
After cleaning both nozzle banks, the system was restored to operability. During a scheduled semi-annual test of both trains of the filter bank fire detection system, the nozzles were again inspected.
Several more nozzles were found to be obstructed from the February 4, 1987, inspection and were replaced while the remaining nozzles were again cleaned.
The licensee has committed to performing addi-tional nozzle inspections during the next refueling outage, tentatively scheduled for November 1987, which is being tracked as Unresolved Item (86-15-03).
LER 87-01: Reactor Trip / Turbine Trip During Pedestal Checks and Failure to Perform Startup Surveillunce The initial review of the reactor trip can be found in detail 4.b.2 of In-spection Report 50-334/87-02.
The inspector has since verified that OST 1.26.4, Pedestal Checks, has oeen revised in accordance with the licensee commitments contained in the LER.
Concerning the missed surveillance test (OST 1.2.1), a Notice of Violation was issued (87-02-01) and is currently awaiting formal licensee response.
During the reactor startup of February 7, 1987, discussed in detail 4.b.1 of this inspection report, the inspector confirmed additional corrective actions outlined in the LER.
LER 87-02: Reactor Trip / Turbine Trip Due To EHC Malfunction This event is discussed in detail 4.b.1 of this inspection report.
The in-spector identified no concerns related to the information provided in the LER.
7.
Onsite Safety Committee During a Region I Specialist inspection of BV-2, a concern relating to the Unit 1 OSC review of procedures was identified. An inconsistency was identi-fied between SAP 10, Onsite Safety Committee, and the requirements of Unit 1 Technical Specification 6.5.1.6.
This TS requires the OSC to review all safety procedures and changes thereto, while SAP 10 only charges the OSC with the responsibility for review of changes to the intent of those procedures.
Additionally, TS 6.8.3 requires that temporary changes may be made to proce-dures provided the change is reviewed by the OSC within 14 days.
However, SAP-10 does not charge the OSC with review responsibility of temporary changes.
The licensee has submitted a technical specification change request (No. 106),
dated January 15, 1986, which would allow the OSC to only review changes of intent to those procedures.
The licensee has committed to continue reviewing both intent and non-intent changes until the TS change request is approved.
In the event that it is not approved, the licensee committed to revise SAP-
- 0 to reflect the TS requirements.
The acceptability of SAP 10 is an Unre-solvec Item (67-05-03) pending the incorporation of review responsibilities for temporary procedure changes and the final disposition of the subinitted TS change.
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8.
MOS Review of Incident Reports During a review of the Maintenance and Operations Subcommittee agenda material, the inspector noted that many of the individual plant incident report reviews were not progressing from the draft incident report stage through the Opera-tional Assessment Group review, OSC review and final MOS review until about 9 months to 1 year after the initial event.
Though those individual events that had warranted issuance of an LER were reviewed within the required 30 day time period, numerous other events had not received the final review and closecut in a timely manner.
This was brought to the attention of the MOS Chairman, who informed the inspector that he also recognized the deficiency.
The inspector was informed that corrective actions were being considered to ensure review and closecut of these items in a more reasonable time frame (about 4 weeks).
The inspector found this to be satisfactory and had no fur-ther concerns at this time.
9.
Fifth Refueling Outage Cable Installation A Region I Specialist identified a concern relating to the storage of safety-related cable at the Unit 2 site.
Specifically, the ends of the cable were found not to be wrapped or otherwise protected while in outside storage.
Some of the cable ends were actually observed to be resting in puddles of water, which could result in a wicking effect whereby water is internally transported through the cable, and over some period of time, degrades the cable insulation.
Because some of this cable could have been installed in the Unit 1 project during the Fifth Refueling Outage in support of various modifications, this item was brcught to the licensee's attention for evaluation.
By memo dated February 2, 1987, the General Manager of NED provided the re-sults of the electrical and control engineering review of the project activi-ties of Unit 1 which had used Unit 2 cable during and subsequent to the Fifth Refueling Outage.
This review identified two groups of cable, those main-tained by the Unit 1 construction project'and those maintained by the Unit 2 project to support the Unit 1/ Unit 2 interface activities. With the excep-tion of limitorque operator environmentally qualified wire replacement, no Unit 2 cables were identified by the licensee as being used on Category 1 installations.
The limitorque operator wire replacement was part of the group that was stored at the Unit I site and not subject to the wicking concerns.
Licensee actions were satisfactory.
10.
Balance of Plant Maintenance The NRC is currently conducting a limited trial program to inspect a generic balance of plant (BOP) system that has been shown to be a significant contri-butor to both unplanned safety system challenges and overall plant risk from a probablistic risk assessment (PRA) prospective.
Recent NRC and industry reports analyzing unplanned reactor shutdowns have demonstrated that a major-ity were caused by BOP initiated transients.
T'e feedwater system (FW) was chosen as the focus of this inspection since it was the single system most responsible for unplanned reactor trips above 15% power during 1984 and 1985.
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Additionally, the FW system has been a significant contributor to plant risk in many plant PRAs (although it is recognized that BV-1 does not have a plant specific PPA).
The inspector reviewed operations and maintenance historical data for the FW system to identify components that contribute to plant unavailability or have caused (or complicated recovery from) plant trips and transients.
The in-spector review of Monthly Operating Reports for the last 18 months of opera-tion, show that in 9 monthly operating periods, 13 manual plant shutdowns, power reductions or power holds were directly attributable to feedwater prob-lems. Further, a majority of the total plant problems during this period, were caused by B0P anomalies.
Failure data indicates that two major feedwater components contribute to the majority of the Es0P failures; the FW regulating valves (FRVs) and the FW pump seals.
A review of station incident reports /LER tracking orogram showed that over 30 incidents occurred in the plant's 10 year operation which were caused by the FRVs.
DLC implements SAP No. 26, 80P Quality Program, whose purpose is to describe a B0P quality program to provide optimum reliability of non-safety related equipnent that is essential to the electric generating capacity of the plant.
Performance oriented procedures were developed to minimize transients that could damage equipment or challenge safety systems.
Although trending of 80P equipment failures does not automatically demand attention, a mechanism does exist to initiate corrective actions.
The repetitive nature of both the FRV and FW pump seal failures was the subject of a management request to perform a Reliability, Availability, and Maintainability (RAM) analysis of the feed-water system.
The study showed that since 1976, the two FW pumps experienced 22 separate problems for which the corrective action included replacing or rebuilding the pump seals.
FRVs were not specifically addressed in the RAM analysis.
The study concluded that the pump seal failures do not follow any type of consistent trend and consequently, the preventive maintenance program was not addressed in that report.
To support a recent proposed FRV modification, the licensee summarized FRV performance data and its effects on plant operation.
The summary indicated that over an approximately 3 year period, 14 outages have occurred, each in excess of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />.
To find a solution to the feedwater system problems with associated conclusions and recommendations, the licensee management requested a special feedwater system task force be formed in December 1986, to perform an in-depth evaluation of this subject.
This task force is currently focusing on this problem and expects to present their results and conclusions to senior management by about June 1987.
The inspector reviewed the licensee's PM Program for the feedwater system.
Currently, only one PM procedure exists in the program for lubrication of the
feedwater motor coupling and oil change.
Additional preventive maintenance is performed on these pumps apart from the PM program.
It includes a major pump overall every 3 years and pump seal replacement and bearinp i..gection
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during each refueling.
There is also a weekly surveillance on the FRVs (per MSP 24.41) which is a visual inspection of each actuator.
The FRVs are also taken apart and visually inspected each refueling outage (informal PM).
Interviews with plant personnel indicate that the root cause of the problems are different for the FRVs and the feedwater pump seals.
The FRVs have under-gone many modifications to make the valves suitable for the application at BV-1.
Similar FW system design changes have been performed at BV-2.
Other modifications are currently planned for the sixth refueling outage.
With respect to the FW pump seals, the types and frequency of failures indicate a maintenance /PM problem.
Some FW pump seal problems resulted in shutdowns or power reductions to rework the same basic problem as previous shutdowns.
The Training Department was interviewed concerning maintenance personnel training.
The program is partially accredited by INP0 and implements a mini-mum job training concept.
However, neither the Training or Maintenance De-partments maintain a list of personnel who are qualified to perform certain jobs.
The Training Department indicated that implementation of a qualification list is a long-term goal.
Currently, personnel are chosen on an as-available basis by Maintenance Supervisors who know the individual's qualifications.
The 80P Program the licensee implements is a slowly evolving program with many informal aspects.
The lack of coordination among multiple plant groups tends to weaken the 80P system in that trends can go unrecognized, increasing the probability of unnecessary challenges to safety-related systems.
The absence of a root cause analysis program for B0P systems results in not ensuring that broad programmatic areas that are contributors to component failures or events are recognized and addressed.
While very few automatic plant trips have occurred due to B0P systems, multiple equipment failures which decrease the reliability of the FW system have continued to occur.
In conclusion, the station is implementing an informal program on many of the critical secondary side components.
In response to recent industry events and INP0 concerns, a more formal program is evolving for B0P equipment.
Based on Beaver Valley's own operating history and experience with the feedwater system, additional management support in this area is warranted.
11.
TMI Action Item Update Item II.K.3.5, RCP Trip Criteria NRR completed their technical review of this item and issued a safety evalu-ation report on January 7, 1987, concluding that the material submitted ade-quately addressed the acceptance criteria identified in Generic Letter 85-12.
The inspector reviewed the SER and compared the information contained within to actual plant procedures.
The RCP trip criteria selected was the secondary pressure dependent RCS pressure criterion.
Inspector review of OM Chapter 1.53, Emergency Operating Procedures, indicated that a 145 psig differential pressure was selected (510 for adverse containment).
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Reference to instrumentation identification including redundancy, quality levels and environmental qualification were verified to be correct based upon a control board walkdown and the NRC environmental qualification audit (In-spection Report 50/334-86-12).
Instrumentation uncertainties for an adverse containment environment were also found to be consistent with plant procedures.
The inspector noted that the E0P instructions for RCP restart did not appear to contain definitive instructions for initiating RCP thermal barrier cooling and seal injection flow to avoid high thermal stresses.
Specifically, the 1* F per minute range cooldown rate referenced in A0P-20, Loss of CCR and Neutron Shield Tank Water, was not referenced.
This was brought to the at-tention of the Procedures Group for a future revision, and a procedure change was initiated.
Through discussions with Operations personnel, the inspector verified that training and procedures had been provided to trip the RCPs based on successful operation of the safety injection system and selected plant parameters reach-ing critical setpoints.
Licensee action in this regard is satisfactory; this action item is closed.
Item I.C.1, Short Term Accident and Procedures Review The Emergency Operating Procedure guidelines for both inadequate core cooling (2.b) and transients and accidents (3.b) is currently under generic review by NRR.
Discussions with the License Project Manager indicate that this issue will be jointly addressed for both Beaver Valley Unit 1 and Unit 2 by approxi-mately June 1987.
Item I.D.2, Plant Safety Parameter Display Console By letter dated April 9, 1986, NRR requested additional information from BV-1 on the safety parameter display system.
A response was requested within 45 days of receipt of that letter to allow for review and closeout of Generic Letter 82-33.
As of February 12, 1987, no response had been forthcoming.
The inspector brought this to the attention of senior licensing management and the response was subsequently issued on February 17, 1987.
It is cur-rently under NRR review.
Item II.F.2, Instrumentation For Detection Of Inadequate Core Cooling DLC has committed to upgrade their ICCS using the generic u v.inchouse design by the Sixth Refueling Outage scheduled for November 1987.
Itis design will incorporate the Reactor Vessel Level Indication System whict f3 currently inoperable.
Inspector discussions with plant management inohated that the
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system was inoperable due to deficient power supply control cards which have been back-ordered through Westinghouse, the vendor, for over one year. The inspector was satisfied that the station had been making reasonable attempts to return this currently non-technical specification required system to ser-
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12.
Chlorine Detection Systems During performance of the monthly control room chlorine detector channel functional checks per MSP 44.05 and 06 on February 11, 1987, the Shift Super-visor determined that the procedures were deficient in that they did not trip the respective channels when the detectors were removed from service.
This appears to be contrary to TS 3.3.3.7 which requires the channels to be tripped if out-of-service for greater than one hour.
To complete the procedure, the channel trip was simulated by lifting one set of leads.
Since no trip switches were provided, an engineering memorandum has been issued to have them installed.
Corrective action in regard to this apparent design / procedure de-ficiency will be reviewed in a future inspection report.
During continued work on upgrading the chlorine detectors per DCP 788, the neutral lead on CLA-VS-1018 was momentarily shorted to ground.
Since this is an input to the Solid State Protection System, Train B, an input cabinet fuse was blown for the No. 3 instrument supply.
This particular power supply only controls various auxiliary contacts out in the plant, and is separate from the input into the Solid State Protection System logic cabinets.
The system was restored to normal using the applicable maintenance surveillance procedure.
Licensee review determined that the root cause of this event was due to an inadequate procedure in that it did not recognize that the neutral lead was " floating" and special precautions are necessary.
Inspector discus-sions with station personnel indicated that appropriate steps were instituted prior to work on CLA-VS-101C. Both the monthly and annual MSPs are being re-vised to either place the channel in trip or limit the time it is out of ser-vice.
The inspector had no further concerns.
13.
Hydrogen Recombiners During startup from the Fifth Refueling Outage, the station encountered dif-ficulties in meeting the flow requirements of TS 4.6.4.2.b.3 for the Hydrogen Recombiner System that was modified under DCP 621.
These problems were dis-cussed in detail 10 of Inspection Report 50-334/86-18.
After conducting a series of tests, the licensee had to modify the system by removing the weight loaded swing check valve internals because the new centrifugal blowers were not able to overcome line resistances with the containment at design vacuum.
This new configuration appeared to be contrary to general design criteria 56 and would require a change to TS Table 3.6-1, Containment Isolation Valves.
After several conference calls between the licensee, NRR and Region I, the description of this physical change as contained in DLC Safety Evaluation of August 26, 1986, was found acceptable and the station was granted verbal per-mission to restart while proposed operating change request No. 130 was pro-cessed by NRR.
In the interim, Region 1 would exercise discretionary enforce-ment action until NRR completed their final review.
Subsequent inspector discussions with DLC Licensing personnel indicated that they examined two options: (1) request an exemption from general design cri-teria 56, or (2) indicate that they meet general design criteria 56 on some other defined basis.
The calculation package, Dose Rate at Hydrogen Recom-
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16 biner Discharge Containment Isolation Valves ia the Main Steam Valve Room, was just completed on November 17, 1986.
This provides the station's basis for meeting GDC 56.
The inspector noted that the time frame between startup and final resolution of this problem appears excessive.
This comment was noted by senior management.
14.
Compatibility of Dual Unit Commitments A region-based specialist inspection of BV-2 identified a concern relating to the biennial review of BV-1 Station Administrative Procedures (SAP).
BV-1 is committed to the 1972 edition of ANSI N18.7, Administrative Controls and QA for the Operational Phase of Nuclear Power Plants, while BV-2 is committed to the 1976 edition.
One difference between these two standards is that the 1972 edition requires an audit of plant procedures on some appropriate fre-quency, while the 1976 edition defines that frequency as once per two years.
The inspector found that a significant portion of the SAPS (currently in effect at BV-1 and soon to be in effect at BV-2) had exceeded the two year review cycle; several had not been reviewed for up to five years.
This item was brought to the attention of DLC QA management.
The inspector stated that it appeared that the station had deviated from the current indus-try practice of implementing a biennial review period for safety related pro-cedures at BV-1.
Further, as these and other common activities that affect both units could be subject to dual commitment requirements, it would be appropriate to identify and re-examine those differences.
These concerns were acknowledged by the licensee.
15.
Exit Interview Heetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings.
A summary of inspection findings was further discussed with the licensee at the conclusion of the report period.
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