IR 05000334/1988022
| ML20151U568 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 08/12/1988 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20151U547 | List: |
| References | |
| 50-334-88-22, 50-412-88-16, NUDOCS 8808190177 | |
| Download: ML20151U568 (22) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.:
50-334/83-22 License Nos.: OPR-66 50-412/88-16 NPF-73 Licensee:
Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279 Facility Name: Beaver Valley Power Station, Units 1 and 2 Location:
Shippingport, Pennsylvania Dates:
June 1 - July 15, 1988 Inspectors:
J. E. Beall, Senior Resident Inspector
M. Pinda e, Resident Inspector Approved by:
cWil E, pp, Chief Date Reactor Projects Section No. 3A Division of Reactor Projects Ing ection Summary:
Combined Inspection Report No. 50-334/88-22 and 50-412/85-16 for June 1 - July 15,1988.
Areas Inspected:
Routine inspections by the resident inspectors of licensee actions on previous inspection findings, plant operations, security and physical protection, radiological controls, plant housekeeping and fire pro-tection, maintenance activities, surveillance testing, annual fire drill, defective 4 KV overcurrent relays, emergency diesel generator problems, cable sepa ra tion, in office review of licensee event reports and review of periodic and special reports.
Results:
One violation was identified regarding inadequate cable separation (Section 10). A licensee identified violation involving the failure to verify emergency ditsel generator operability in accordance with Technical Specifica-tion requirements is discussed in Section 4.2.5.
Three unresolved items were opened regarding (1) T.he resolution of the overcooling event that occurred fol-lowing the June 7 reactor trip which resulted in a subsequent safety injection (Section 4.2.1), (2) more action wh1ch may be necessary to prevent events which could result in a complete loss of the Unit 2 control room annunciator system (Section 4.2.G), and (3) recurrent problems that have been experienced on the emergency diesel generator air start systems (Section 9).
Continued improve-ments were noted in plant housekeeping and licensee event report quality, bo lC c> 3
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TABLE OF CONTENTS Pate 1.
Persons Contacted......................
2.
Summary of Facility Activities
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3.
Followup on Outstanding Items (92701)............
4.
Plant Operations
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4.1 General (71707, 71710).....
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4.2 Operati on s ( 71707)................,..
4.3 Plant Security / Physical Protection (71881)
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4.4 Radiological Controls (71709)
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4.5 Plant Housekeeping and Fire Protection (71707)
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5.
Ma'ntenance (62703)
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6.
Surveillance Testing (61726).................
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7.
Annual Fire Orill (64704)......
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8.
Defective 4 kV Relays (71707, 90712).
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9.
Emergency Diesel Generator Problems (71707,.61726, 62703)..
10.
Inadequate Cable Separation (71707, 71710)..........
11.
Inoffice Review of Licensee Event Reports (90712)......
12.
Review of Periodic and Special Reports (90713)
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13.
Unresolved Items
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14.
Exit Interview (30703)
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OETAILS
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persons Contacted During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspec-tion activities.
2.
Summary of Facility Activities At the beginning of the inspection period, both Unit I and Unit 2 were operating at full power.
A Unit I reactor trip and safety injection occurred on June 7 when a non-licensed operator inadvertently tripped an operating reactor coolant pump, causing a low reactor coolant flow condi-tion (Section 4.2.1).
Two additional Unit 1 reactor trips occurred on June 9 (Section 4.2.2) and June 11 (Section 4.2.3) during plant startup evolutions, and were due to feedwater system control problems which re-suited in low-low steam generator water level reactor trips.
Operator error contributed to the June 9 reactor trip. The plant was subsequently restarted and full power was reached on June 13, and continued until the end of the inspection period. On June 15, a rapid manual turbine / genera-tor load reduction was initiated on Unit 2 in response to degraded con-denser parameters.
A secondary plant shutdown followed for turbine pro-tection, while the reactor was maintained at a low pwer level.
The tur-bine/ generator unit was placed back on line that same day and full power
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operation resumed on June 16, and continued to the end of the period.
3.
Followup on Cutstandino Items The NRC Outstanding Items (01) LBt was reviewed with cognizant licensee
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personnel, items selected by the inspector were subsequently reviewed
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through discussions with licensee personnel, documentation review
.nd field inspection to determine whether licensee actions specified in the Ols had been satisf actorily completed.
The overall status of previously identified inspection findings was reviewed, and planned / completed licen-see actions were discussed for the items reported below:
3.1 (Closed) Unresolved Item (50/334/88-11-02):
Open Cable Junction Boxes and Cable Tray Cover Deficiencies.
This item involved the identification by the inspector of several deficiencies in the Unit 1 cable spreading room directly beneath the control rocm.
Cable junc-tion boxes were found open and numerous cable tray covers were found missing, damaged or improperly installed.
The licensee acted promptly to correct the identified deficiencies including repair /
fabrication and installation of additional tray covers.
The inspec-tor conducted a followup inspection and noted that the identified deficiencies had been corrected. This item is closed, however, addi-tional deficiencies were identified in the cable spreading room dur-ing the inspector's walkdown as discussed in Section 10 and a viola-tion has been opened.
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3.2 (Closed) Unresolved Item (50-334/88-17-01): Inadequate Cable Separa-tion. This item involved portable cables which were routed in such a way as to provide inadequate separation with existing safety related cable. The licensee corrected the identified deficiencies, conducted area and overall plant walkdowns, and corrected additional self-l identified items. This item is closed, however, additional separa-l tion deficiencies were identified by the inspector as discussed in l
Section 10 snd a violation has been opened.
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Plant Operations 4.1 General Inspection tours of the following accessible plant areas were con-
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ducted during both day ar.M night shifts wi'.h respect to Technical Specification (TS) compliance, housekeeping and cleanliness, fire protection, radiation control, physical security / plant protection and operational / maintenance administrative controls.
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-- Control Room
-- Safeguard Areas
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-- Auxiliary Building
-- Service Building
- Switchgear Area
-- Diesel Generator Buildings
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-- Access Control Points
-- Containment Penetration Areas
-- Protected Area fence Line -- Yard Area
-- Turbine Building
-- Intake Structuro The operability of selected Engineered Safety Features systems were verified by performing detailed walkdowns of the accessible portiens l
of the systems. The inspectors confirmed that system components were in the required alignments, instrumentation was valved-in with appru-l priate calibration dates, as-built prints reflected the as-installed l
systems and the overall conditions observed were satisfactory.
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systems inspected during this period include the Emergency Diesel Generator, Safety Injection and Auxiliary Feeawater systems. No con-cerns were identified.
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Ouring the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures, facili',y configuration and plant conditions. During plant tours, logs and records were reviewed to determine if entries were properly made, and that equipment status / deficiencies were identified and communi-i
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cated. These records included operating logs, turnover sheets, tag-out and junper logi_ process computer printouts, unit off-normal and draft incident reports. The inspector verified adherence to approved procedures for ongoing activities observed.
Shift turnovers were witnessed and staf fing requirements confirmed. Inspector comments or l
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questions resulting from these reviews were resolved by licensee per-sonnel.
In addition, inspections were conducted during backshif ts and weekends on June 3, 6:00 pm - 11:00 pm; June 8, 6:00 pm - 8:30 pm; June 12, 10:00 am - 7:30 pm; June 28, 6:00 pm - 8:30 pm; June 30, 6:00 pm 9:30 pm; July 1, 4:00 am 7:00 am; July 7, 2:00 am
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7:00 am. The inspectors verified that plant operators were alert and displayed no signs of fatigue or inattention to duty.
4.2.1 Reactw Trip and Safety Injection On June 7, a reactor trip and safety injection (SI) occur-red at Unit 1 from full power during the performance of a balance of plant surveillance test.
Operations personnel were in the process of testing a station air compressor, whtn the procedure instructed them to open the associated
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480 V AC breaker. A non-licensed nuclear operator inadver-s I
tently opened the 4KV
"C" reactor coolant pump (RCP)
breaker (105) instead of the 480 V AC station air compres-sor breaker (2C5).
The loss of the "C" RCP resulted in an automatic reactor coolant system (RCS) low flow reactor i
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trip at 9:55 p.m.
A low pressurizer pressure safety injec-
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l tion automatically actuated 29 seconds following the reac-
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i ter trip.
An Unusual Event was declared at 10: 12 p.m. in l
accordance with the Emergency Preparedness Plan (due to ECCS actuation). The SI system injected borated water into the RCS for about 17 minutes before the SI was terminated.
l The Unusual Event was terminated at midnight following plant stabilization and verification of shutdown margin.
The licensee notified the NRC of the event in accordance I
with 10 CFR 50.72 reporting requirements.
Several problems were encountered during the event, includ-ing (1) the reason for reaching the low pressurizer pres-sure SI setpoint following an aralyzed reactor trip was not apparent, (2) no first-out reactor trip annunciator was l
received, however, reactor operators observed the irip of l
the "C" RCP, the opening of the reactor trip breakers, and l
the control rods falling into the core, and (3) both emerg-ency diesel generators (EDGs) automatically started as designed, hewever, the EDG No I lef t bank tir start motor pinions continued to attempt to engage (See Section 9 for additional details on the EDG system).
The Heensee found a faulty timer relay in the first-cut logic control cir-cuitry for the "C" RCP. A new relay was ordered and will l
be installed at a future time. Computer peintouts also log i
the tripping of an RCP breaker.
The inspector will verify
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that the timer relay is replaced during a sub*,equent inspection.
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The licensee performed a detailed review of the June 7 reactor trip to determine the exact cause of the SI actua-tion. A simulator run was performed, however, was incon-clusive.
The licensee subsequently identified two dominant factors that contributed to the rapid primary plant depres-surization.
First, a rapid RCS cooldown and depressuriza-tion resulted f rom an over-response of the steam dump. sys-tem due to a stagnant resistance temperature detector (RTO)
manifold temt.erature in the "C" loop af ter the associated RCP was tripped.
There are five. valt J$ on the "C" RTD by-pass manifold which had previously (5 ince 1984) experienced disc / stem separation problems.
Und.r reversed flow condi-l tions, the valves act to stop flow, thus causing the stag-
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nant conditions which provided a false high average temper-ature signal.
Second, the main feedwater regulating valve (FRV) trim modification, performed during the recent sixth refueling outage, increased the post-trip feedwater flow through the FRVs resulting in a more rapid cooldown.
The severity of this effect is greater following a reactor trip that occurs during iou power operations, ';ince there is very little feedwater heating and upon a reactor trip, the l
FRVs initially open fully.
Although the licensee deter-l mined that the first item appears to be the most dominant i
contributor, they have determined that the absence of I
either item would have precluded an SI actuation. This was confirmed on a subsequent plant trip on June 11 (without
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i loop flow reversal).
Pressurizer pressure dropped to 1880
psig on the June 11 reactor trip which is still very close to the $1 actuation pressure of 1845 psig.
The normal post-trip for pressurizer pressure should be about 2050 l
psig. This indicates that feedwater overfeeding remains a significant and continuing concern warranting additional licensee attention.
The licensee plans to remove the RTO manifold during the next refueling outage and replace the existing RTD with
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in-loop temperature instrumentation, a modification which will eliminate the 'oypass manifold stagnation c.oncern. One
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fix which was instituted for the overfeeding concern was a j
change in the closure time for the FRVs from a minimum of 7 seconds to 5 seconds.
This change is expected to reduce feedwater flow into steam generators and therefore, has the potential for reducing the possibility of experiencing similar RCS overcooling events immediately following a reactor trip. A related short-term licensee action was to j
provide instructions to plant operators to verify that the i
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4 auxiliary feedwater system is operating properly and to trip the main feedwater pumps if RCS pressure reaches 1950 psig following a reactor trip.
These actions are expected I
to avoid an excessive cooliiwn and provide an adequate mar-
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gin to the SI signal setpoint.
Further review and imple-mentation of additional recommendations are currently under review by the licensee.
Final resolution of the overcooling concerns will be reviewed during a subsequent inspection (Unresolved Item 50-334/88-22-01).
l 4.2.2 Feedwater Isolation and Reactor Trip l
On June 9, a Unit I automatic reactor trip occurred from about 16*. power during a plant startup following the June 7
reactor trip (Section 4.2.1).
Adjustments had been com-l pleted earlier on the b/ pass feedwater regulating valves l
(BFRVs) in order to minimize flow oscillations that were i
experienced previously.
Shortly af ter the unit was syn-
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chronized onto the system grid, steam generator water level i
oscilittions were experienced as noted on all three steam
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generator level recorders. The "A" and "B" steam generator level swings appeared to be stabilizing, while the "C" con-tinued to oscillate. The "C" controller was placed in man-
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l ual, however, the high level setpoint was reached on that l
steam generator despite operator efforts to prevent large l
level oscillations.
The high steam generator level caused I
a turbine trip, feedwater isolation and an automatic trip of the operating main feedwater pump.
Both motor driven auxiliary feedsater pumps automatically started as de-
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signed.
Af ter the
"C" steam generator level was restored to normal, the main feedwater pump was restarted and the l
auxiliary feedwater system secured. However, the feedwater l
water isolation signal was not reset by tne plant operators I
and therefore, the feedwater isolation valves remained j
l closed, preventing feedwater from reaching the steam gen-i
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erators.
Within several minutes, steam generator water levels drif ted downward until a low-Icw level reactor trip i
signal was generated on the "A" steam generator. Emergency operating procedures were followed by plant operators and the unit was stabilized in Mode 3.
The licensee notified the NRC of the event in accordance with 10 CFR 50.72 re-porting requirements.
The initiating cause of this event was the failure of the "C" BFRV to adequately control steam
generator water level while operating in the automatic mode. Additional checks and tuning of the BFRVs were per-formed.
No hardware problems were found, but additional
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troubleshooting ac',1vities were being performed at the end of the inspection.
The licensee attributed the failure to reset the feedwater isolation signal to be a knowledge and experience deficiency that will be addressed through the Operator Retraining Simulator o rogram.
The inspector will review the results of the BFRV troubleshootihg activities and the effectiveness of the licansee's propused corrective actions during subsequent routine inspections.
4.2.3 Feedwater Isolations and Reactor Tfjy On June 11, Unit 1 experiencea two feedwater isolations (FWIs) and a subsequent reactor trip from 13*. power during the recovery from the reactor trip on June 9.
During the
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startup evolution, steam generator (SG) feedwater level control was transferred from the bypass feedwater regula-ting valves (BFRVs) to the main feedwater regulating valves (MFRVs) at 13*e power.
Level control is normally trans-ferred to the MFRVs at between 20*; - 25'4, however, control was transferred earlier during this startup in an attempt to eliminate control problems similar to those previously
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Plant operators l
were planning to bring the main turbine on-line with the l
MFRVs in service; however, the SG automatic level control l
system began to experience instability problems in that
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feedwater flow and SG 1evel oscillations were noted. Al-though the operators attempted to reanually control SG 1evel, the
"C" SG 1evel increased in its high setpoint, resulting in a PWI.
The PWI signal > >tomatically caused (1) feedwater flow to be isolated; (2) a trip of the oper-ating ("A") main feedwater pump (MFWP) and (3) en auxiliary feecwater system actuation.
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"C" SG water level was returned to normal within several minutes, the FWI signal was reset, associated equipment restored to normal ("A" MFWP was restarted) and the plant startup continued.
The turbine was then placed l
on-line.
SG level oscillations occurred again and another l
PdI signal was generated when the "A" SG water level rathed
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its high level setpoint.
The automatic Pdl actions occur-red as designed, including an automatic turbine trip (the turbine was not on-line when the first FWI occurred).
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7 SG water levels were again returned to normal within a few minutes.
Plant operators reset the FWI signal and at-tempted to restore normal feedwater flow by starting the
"B" MFWP.
The
"B" MFWP was selected so as to reduce the number of consecutive starts of the "A" MFWP over a short period of t'ime (per procedure).
Control roem operators noted a lower than normal feedwater flow following the pump start, it was than identified that the "B" MFWP discharge valve had not fully opened when the pump was c. tarted.
Con-trol room operators iinmediately secured the
"B" MPdP and started the "A".
Normal feedwater flow was then observed, however, before the feedwater system was able to recover the decreasing SG water levels, the icw-low level setpoint was reached on the "A" SG, resulting in an automatic reat-tor trip. Plant operators stabilized the plant in Mode 3 using Emergency Operating Procedures.
All three events were reported to the NRC in accordance with the reporting requirements of 10 CFR 50.72.
The licensee's followup investigation identified that un-stable SG 1evel control occurred because 1) under low flow
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conditions, the MFRVs do not respond as quickly as the BFRVs, and 2) without the turbine on-line, no extraction steam was available for feedwater preheating (feeding the SGs with relatively cold water contributed to the level stability problems).
The
"B" MPdP discharge valve motor-operator was tested to determine whether an electrical failure had occurred, however, no problems were fcund, l.icensee investigation ir.to the reasons for the failure of the "B" dis:htrge valve to open is continuing and will be reviewed during a subsequent inspection.
The licensee pr ovided instructions to plant operators to address the above concerns, including requiring that future plant startups be perforced using the BFRVs until the reac-
tor reaches at least 20*i power and to perform the turbine startup at lod pcwer levels in order to rnake extraction steam available for feedwater preheating.
The licensee also discovered that two condenser steam dump system valves were not operating properly during this etent, resulting in pressure surges that may have contributed to the SG 1evels control problens.
The affected valves have been failed closed pending repairs.
The inspe-tor will monitor the effectiveness of the licensee's corrective actions during subsequent inspect 1ons, i
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4.2.4 M_ain Condenser problems On June 15, at 2:55 pm, Unit 2 control roca operators initiated a load reduction in response to degraded conden-ser vacuum and temperature conditions. The power decrease and subsequent feed and bleed evolutions that were initi-ated to correct the problems failed to improve condenser vacuum or hotwell temprature.
Within two hours, minimum load was reached on the main turbine / generator (10 MWE).
At 5:00 pm, the turbine was manually shut down, the main generator output breakers were opened and the turbine was manually shutdown.
The hotwell temperature returned to normal within several minutes, however, condenser vacuum did not return to its normal expected value. At 6:38 pm, vacuum was better and increasing while air ejector flow was decreasing.
The licensee speculated that earlier air injector performance may have been degraded.
All parameters were subsequently returned to normal and a tur-bine startup commenced.
Full power was reached on June 16.
The licensee's followup investigation into this event iden-tified several factors which may have contributed to the event. The first is that the outside temperature was high (93 F), which accounted for the initially higher hotwell
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temperatures.
Earlier on June 15, the steam generator blowdown demineralizer was placed on clearance for mainten-ance, and the relatively hot blowdown flow was directed to the condenser botwell. At 4:25 pm, the air ejectors back-fired, dumping a relatively large amount of air into the condenser (when condenser parameters were already degraded). Additionally, during the feed and bleed evolu-tion, a 4 inch valve was used versus an available 12 inch hotwell fill valve, which would have been more effective in reducing the hotwell temperature.
At the time of the event, plant operators had instructions to initiate a power reduction when the condenser back-pressure reaches a predetermined value.
Hotwell tempera-ture was not r ferenced in the Instructions. Once satur6-e tion conditi ns were reached during this event, efforts to o
restore the paramenters to normal were ineffective.
To reduce cl.e possibility of similar occurrences, the licensee developed a Condenser Back pressure versus Condenser Outlet Cooling Water Temperature curve, which was provided to plant operators. The curve provides points at which power
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reduction should be initiated to prevent reaching satura-tien conditions in the main condenser. A similar curve was-developed for Unit 1.
The licensee also began trending condenser parameters to monitor condenser operation. Addi-tional significant events relating to degraded condenser performance have not occurred subsequent to the development
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of the performance curvos.
The inspectors will monitor condet.ser performance and operator response to adverse conditions during routine inspections.
4.2.5 Failure to Verify Diesel Generator Operability On July 7, the Unit 1 No. 1 Energency Diesel Generator (EDG) was removed fron service to inspect and clean the air lines in the EDG air start syste's at 11:56 a.m. (Section 9)
fellowing the air start system fe.ilure on the previous day.
Technical Specification (TS) 3.8.1. Electrit.al Power Sys-tems, requires that the remaining EDG (No. 2 in this cate)
be demonstrated to be operable and that the offsite to on-site power distribution system breaker alignment be verif-1ed.
At 2:38 pm, oncoming snif t personnel questioned if
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the above actions were ptrformed.
When onshift Contiol Room personnel realized that those actions were not per-formed, the No. 2 EDG was immediately manually started from the Control Room and the appropriate checks were success-fully completed at 2:50 p.m.
The No. 2 EDG had last been demonstrated to be operable at 4:06 p.m. on July 6, when the No.1 EDG was inoperable due to the failure of the air start system.
That EDG was re-turned to servici later that day, and then again removed from service at 11:56 a.m.
on July 7.
Th.e operability checks were missed due to personnel error possibly as the
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result of a
=4 tunderstanding of the previous testing and period of inoperability. Ir addition to the imediate cor-rective actions of verifying the operability of the No. 2 EDG, a procedure change has been completed which now spec-i ifies that the required operability verification for the remaining EDG be completed when one EDG is taken out of service.
Additionally, Station Administrative Procedure No. 41, Clearance Procedure, will be reviewed to determine whether additional changes or instructions are needed to the emergency safeguards equipment clearance checklist.
The inspector will independently review this procedure to determine whether changes are necessary.
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e Since the failure to meet the above TS requirements was
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identified by the licensee And this situation meets the criteria to be considered a Itcensee identified violation, in accordance with the "General Statement of Policy and Procedure for NRC ' Enforcement' Actions," 10 CFR 2. Appendix C, no Notice of Violation will be issued,
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j 4.2.6 Loss of Control Room Annunciator _ System On July 7, Unit 2 experienced a brief (8 minutes) loss of'
control ' room annunciators while operating-at full pnwer.
Prior to the event, technicians were troubleshooting prob-1 ems with one of the three inverters that supply power to the control room annunciator system, During the trouble-shooting activities, the common supply breaker to all three inverters-tripped open due to overcurrent, resulting in a
loss of control ioom annunciator window indication, horns
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and pushbutton control.
A partial loss -of the CRT (com-
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puter) alarm inputs also occurred. The annunciator system
was restored by reciosing the commun inverter supply
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breaker and de-energizing the affected inverter.
For the duration of the event, plant operators monitored plant
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status using the CRT displays, plant computer and available charts and indicators in the control room.
No plant
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transients were experienced-The site emergency plan was
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not implemented because no plant transients were experi-enced and the annunciator loss did not exceed 15 minutes.
On January 28,1988, Unit 2 experienced a two hour loss of control room annunciators due to -a fire which led to the declaration of an Alert.
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Licensee followup investigation and troubleshooting activ-
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ities identified that the cause for the event was a random
component failure of a power bridge silicon control recti-fier (SCR).
The itcensee is currently investigating the feasibility of providing a separate supply breaker for each j
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of the individual inverters, 'hereby preventing a loss of -
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all control room annunciators won a similar type of coin -
ponent failure.
Such a change '..' configuration would also j
facilitate maintenance activities en the inverters.
Pend-
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ing licensee determination of a method to prevent recur-
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rence of similar events, this is Unresolved Item No.
50-412/88-16-01.
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4.2.7 Ircreased,"ain Turbine Vibration
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During this inspection period, increased vibration levels on the No. 4 bearing of the Unit 1 main turbine.were ob-
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served..The licensee requested an-offsite contractor to
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j review and analyze test data on the bearing. The contrac-tor determined that, at the time of the review, the vibra-
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i tion from the beartr.g had doubled (from 2 mils to 4 mils),
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since the recent restart from the sixth refueling outage s
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(March,1988), and had been increasing at a rate of 0.7 mil.s per week. At the end of the inspection, the vibration was relatively constant at about 7 mils.
The contractor-reviewed the vibration data from the most recent plant
startup and found that the turbine had experienced up to 15 mils. overall vibra;.on ampittude for a considerable time r
while passing through the critical turbine rotor. speeds, and concluded that something in the No. 4 bearing. structure-had changed to account for the-elevated vibration levels.
The contractor recommended that a general; bearing struc-
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tural inspection te performed at the next convenient time.
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The licensee instituted increased monitoring and trending
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of the No. 4 bearing.
The licensee determined that if a
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displacement of 8.5 mils sustained or a sustained increas-ing vibration rate of ' greater than 0.5 mils per day is
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reached, the unit should be removed from service and the
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bearing be inspected for looseness and/or damage.
If the
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unit is to be taken off line for a bearing inspection, a 9 j
to 10 day mini-shutdown is expected, and the reactor is l
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planned to be maintained in Mode 3 (Hot Standby).
The inspector will.centinue to monitor the licensee's assoc 1-
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ated activities.
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4.3 Plant Sec qity/ physical Protection
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Implementation of the Physical Security Pian was observed in various
plart areas with regard to the following Protected Area and Vital Area barriers were well maintained and
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not compromised;
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Isolatka zones were clear;
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personnel and vehicles entering and packages being delivered to
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the Protected Area were properly searched and access control was
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Persons granted access to the site were badged to indicata
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whether they have unescorted access or escorted authorization;
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Security acctss _ controls to Vital Areas were being maintained
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and that persons in Vital Areas.were properly authorized.
Security posts' were adequately staffed and equipped, security
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personnel were alert and knowledgeable regarding position
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requirements, and that written procedures were available; and
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Adequate illumination was maintained.
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No deficiencies were identified.
4.4 Radiological Controls Pot control of radiation and high radiation areas wets inspt Radiation Work Permit compliance and u:e of personnel monito,ing devices were checked. Conditions of step-off pads, dis-po5al of protective clothing, radiation control job co'verage. area l
monitor operability and calibration (portable and permanent) and
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personnel frisking were observed on a sampling basis..No concerns were identified.
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4.5 Plant Housekeeping and Fire Protection l
Plant housekeeping conditions including general cleanliness condi-tions and control and storage of flammable material and other poten-tial safety hazards were observed in various areas during plant
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tours. Maintenance of fire barriers, fire barrier penetrations, and verification of oosted -f ire ' watches in these areas were also ob-
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served. The inspector conducted detailed walkdowns of the accessible areas of both Unit 1 and Unit 2.
Continued improvements ~were noted
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for both units.
Individual deficiencies were identified to the licensee for resolution.
5.
Maintenance
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The inspe: tor reviewed selected riaintenance activities to assure that:
I the activity did not violate fechnical Specification Lim; ting Condi-
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tions for Operation and that redundant components were operable;
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required approvals and releases had been obtained prior to commencing
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work;
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procedJres used for the task were adequate and work was within the
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tkills of the trade; activities were accomplished ;y qualified personnel;
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where necessary, radiological and fire preventive controls were ade-quate and implemented; QC hold ooints were established, where required, and observed;
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equipment was properly tested and returned to service.
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Maintenance activities reviewed included:
MWR 882686
~ Change out four Air Start Motors for No. 1 EDG MWR 880776 Replace Air Start Solenoid MWR 880906 Replace No. 1 EDG 1 eft bank solenoid valve
MWR 883103 Replace isolation ' valve for starting air tank EE-TK-4C No significant concerns were identified.
6.
Surveillance Testing The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details were adequate, test instrumentation was properly calibrated and used.. Technical Specifi-cations were satisfied, testing was performed by qualified personnel and test re>ulta satisfied acceptance criteria or were properly dispositioned.
The following surveillance testing activities were reviewed:
M3P 6.10 F-426 Reactor Coolant Flow Loop 2 Protection Channel III Test.
o MSP 6.33 F-426 Reactor Coolant Flow Loop 2 Frotection Channel III Calibration.
MSP 13.05 L-100A Refueling Water Storage Tank Level Loep Channel III
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Test.
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OST 1.30.0 Reactor Plant River Water Pump 1C Test.
OST 1.36.1 Unit 1 Emergency Diesel Generator No. 2 Monthly Test.
OST 2.36.1 Unit 2 Emergency Diesel Generator No. 2-1 Monthly Test.
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The inspector found that' minor-steps in the test. instrument connection
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instructicns.for Maintenance Procedure-(MSP) 6.33 were apparently missing.
Other minor discrepancies were found with respect to incorrect' references to different sections / steps.
The technicians performing the MSP under -
stood what was to be accomplished, however,' less. experienced technicians could possibly be misled. The technicians noted the.apparrnt. human-factor type deficiencies on the attached MSP critique form for lfurther review. -
Additionally, the inspector discussed this concern with the appropriate licensee personnel, who acknowledged the inspector's comments.
No other concerns were identified.
7.
Annual Fire Drill The licensee conducted an annual site fire drill on June 9 to test the response and coordination among the onsite fire. brigade, site security personnel and the offsite fire departments. The drill scenario. included a lightning strike of a Unit 2 station service transformer, causing the sprinkler system water and burning oil to flow cnto the ground.- Both plants were to be operating at 100% power.. Additionally, the scenario included an injured person in the Unit 2 Auxiliary Building during the fire.
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The inspector witnessed the drill and associated activities. The emerg-ency classification of the event (Unusual Event) was made properly and. in a timely manner. Operations support in the control room was observed to be good.
The fire brigade, radiological control, security and offsite fire department members provided similarly good support 'for the drill.
The inspector noted that the licensee' maintains a _ very good working rela-tionship with the offsite fire departments. This is a continuing licensee strength. The drill was terminated when all trucks flowed water and the drill objectives were completed.
A critique was. held by the licensee immediately following the drill. A weakness was identified with respect to the response and first aid treat-ment provided to the injured person. Other' minor deficiencies were iden-
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tified by drill controllers. An evaluation ~ report was issued on June 23, which documents the noted deficiencies, proposed resolutions, responsibil-ities and due dates. These items will be tracked by the licensee's inter-nal tracking.;y s tem.
The inspector reviewed the licensee's evaluation
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drill actisi~ ies. The overall performance of personnel and equipment was
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8.
Defective 4 kV Relays On June 30, the licensee notified the NRC of a deficiency with 4 kV over-current -elays provided by Brown Boveri (Model ITE-51). A relay component provided by Motorola was found to be subject-to failures due to impurities which can cause spurious overcurrent trips.
The components involved are silicon control rectifiers (SCRs), manufactured by Motorola before 1982.
Unit 2 has experienced five such failures (three on safety-related com-ponents). The licensee completed a justificattom for continued operation (JCO) on July 1.
A 10 CFR, Part 21 Report was submitted to the NRC in accordance with the requirements of that section.
The SCR impurity allows leakage current to gradually increase until the component short circuits and automatically trips the relay. Motorola has previously identified the problem and has instituted two different "burn-in" tests, one which subjects the SCR to a test (heat) environment with an applied voltage, while the other subjects the SCR only to 9e test environment. Any relays installed that were purchased prior to 1982 did not have the "burn-in" tests pe rformed.
Therefore, at the licensee's request, the relay manufacturer provided them with a test procedure which could be used to detect suspect SCRs.
The licensee tested all 138 ITE-51 ralays on 4 kV feeder breakers. 46 of them are used in safety-related applica+. ions. Of the 138 relays tested, 11 were found to have leakage corrents greater than the test acceptance criteria. Seven defective relays were installed on safety-related equip-ment. All de'ective relays were replaced.
The licensee's JC0 concluded that continued plant operation was justified because the affected relays were in a continuously energized state (DC power supplied) for a period in excess of two years. The vendor stated that such a service time is equivalent to the "burn-in" test and there-fore, impurities would have been identified via relay failure.
The JC0 also documented that Operations personnel will sper.ifically check for tripped or flagged relays each shift and that there is an annunciation in the control room sequence of events recorder.
The inspector conducted an independent review and found that, upon a relay actuation, a control room alarm and computer printout will be annunciated.
The alarm allows for a prompt investigation into the cause of the actua-tions.
Additionally, plant operators could remove a failed relay from service via a bypass function, if needed. The inspectors will monitor the effectiveness of the Itcensee's actions during routine inspections,
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Emergency Diesel Generator Problems Several problems have been expertenced during this inspection period with the Unit 1 Emergency Diesel Generator (EDG) Air Start System.
As docu-mented in NRC -Inspection Report No. 50-334/88-01, the licensee committed to inspect the air start system associated with one of the EDGs in June of this year.
The results of the inspection and two recent equipment prob-lems are outlined below.
9.1 Air Start System Failure Folicwing EDG Automatic Start On June 2, a Maintenance Wor k Request (MWR) No. 882686 was initiated, which was to change out all four (2 in each bank) EDG No.1 air start motors (ASMs).
They were to bn sent to an offsite contractor for inspection and repair, as necassary.
Before the MWR was worked, a reactor trip and safety injection (SI) occurred on June 7 (Section 4.2.1).
The SI generated an automatic start of both EDGs as_ per
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design, however, during attempts to secure the No. 1 EDG, the two left bank ASM pinions continued to attempt to engage due to an apparent faulty air start solenoid. The EDG was declared inoperable, and all four ASMs (both banks) were replaced. per MWR 882686. The condition of the lef t bank ASM pinions were sufficiently degraded to suggest that they may have not properly disengaged immediately fol-lowing the No. 1 EDG automatic start. The licensee also replaced the lef t bank air start solanoid valve, as it was suspected to have con-tributed to the ASM problem. Following a successful post maintenance test after the replacement of all.four ASMs and the left bank scle-noid, the No. 1 EDG was returned to service on June 8.
9.2 Air Start System Failure During Surveillance Testing On July 6, during a backshif t inspection, the inspector witnessed the performance of Unit 1 Operations Surveillance Test 1.36.1, EDG No.1 Monthly Test. The EDG was manually started from the control room, and within about 10 minutes, sparks were observed coming from the ASM location.
Plant operators immediately locally shutdown the EDG.
The subsequent inspection identified that the left bank ASM pinions had not disengaged. The left bank was then removed from service by isolating the associated air bottles and air compressor, and the No.
1 EDG was declared inoperable. During the time that EDG No. I was
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out of service, EDG No. 2 was demonstrated to be operable and the offsite to onsite power distribution system breaker alignment was verified in accordance with the requiremeats of Technical Specifica-tion (TS) 3.8.1, Electrical Power Systems.
The licensee removed and inspected the left bank solenoid valve and air start motors.
Rust fragments were found on the solenoid valve seat.
The inspection of the ASM !dentified that one pinion was severely damaged, while the other one showed abnormal wear. The left bank solenoid and both ASMs were subsequently replaced with qualified spares. The damaged ASMs were sent to an offsite contractor for inspectico and repairs.
The No. 1 EDG was subsequently tested satisfactorily and returned to service later that day.
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On. July 7, the No.1 EDG was again removed from service so that the licensee could. perform additional detailed inspections of the air start system, including components such as the in-line strainers and related piping.
During the time that EDG N0. I was out of service,
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the licensee identified that EDG No. 2 was r.ot tested in-accordance the the requirements of. TS 3.8.1 (see Secticn.4.2.5).. Rust fragmentss were found in the strainers'and strainer. plugs. The air start piping for both the left and right banks were removed to :nspect forinter-nal rust and debris, and for cleaninp as necessary.
A substantial.
amount of rust was removed from the inside of the pipi.ig_ The No. 1 EDG was successfully retested on July 8 and was returned to service.
On July 11, the No. 2 EDG was taken out of service to clean both banks of air start piping an an ef fort to reduce the possibility for similar problems occurring on that unit.
The provisions of TS 3.8.1 vare satisfied during the time the EDG No. 2 was out of service. The amount. of rust removed from that piping was about the same as was removed from the No. 1 EDG.
9.3. Summary Previous plant nodificatio'ns have been implemented to increase the reliauility of the air start system. These include the addition of pulsation dampers and air start dryer ulits to absorb any rapid air pulses cut of the air compressors and to remove moisture from the air used in the air start system.
These modifications may have improved the quality of air currently used in the system, however, have been ineffective in preventing problems due to the effects of the pre-viously degraded air system.
The licensee has proposed several options to furtier improve system reliability:
1) periodically inspect the in-lane strair.ers, and 2). install. an in-line filter in the system.
The results of the vendor inspections of the ASMs and the determina-tion of lon0 term corrective actions will be reviewed during future inspections. This is an Unresolved Item (50-334/88-22-02).
10.
Inadequate Cable Separation During walkdowns of th? Unit 1 and the Unit 2 cable spreading rooms, the inspector identified several instances of inadequate separation between cable of different safety trains.
Cable separation is required to assure
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that a single failure or event could not impact more than one train of safety equioment.
This requirement is found in the General Design Cri-i teria (10 CFR 50, Appendix A), the ECCS criteria (10 CFR 50, Appendix K)
and the Protection System criteria (10 CFR 50.55a(h)). At Beaver Valley, i
these requirements are documented in BVS-3001 for Unit 1 and 2BV-931 for Unit 2, with respect to cable separation.
Individual tasks such as cable i
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installation, cable wrapping and cable tray cover installation implement the requireirents which differ somawhat between ~the two units.
These activities occur not only during construction, but also during outages as system modifications are performed.
During normal plant operation, other
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activities such as maintenance or surveillance of nearby components have the potential to degrade separation by such things as damaging cable tray covers. The individual tasks associated with safety related equipment are required to be controlled to assure quality.
At. nit 1, the cable in tray 1Tr.5450 was not properly separated from the cable in tray 1TC306B.
Neutral cable was found routed in tray 1TC6080 which then was routed touching cable routed in tray ITC607P. 'In other locations, cable tray covers were absent ruch that the required separation between trays was not being maintained.
Instances of spared cable were found such that the loose coils were stored in violation of separation criteria. These and other deficiencies were identified to the licensee for correction.
At Unit 2, a cover on conduit line 2CC940M was missing and the cable in the line was extruded such that there was inadequate separation with cable 2NNSANC457.
A spare coiled cable exiting tray 2TC403P was found loosely piled together on the floor with cable 2NNSANC457 with no separation.
Other deficiencies such as stn.y and missing tray covers were also iden-tified to the licensee for correction.
This is a violation (50-334/
88-22-03; 50-412/88-16-02).
Licensee corrective actions were in progress at the close of the inspec-tion, including additional walkdowns to look for other deficiencies. The identified deficiencies are similar to the items discussed in Sections 3.1 and 3.2 (previous Open Items).
These findings, taken as a whole, are indicative of a programmatic weakness in the assurance of adequate separa-tion of safety related cable.
11.
Inoffice Review of Licensee Event Reports (LERs)
The inspector re"iewed LERs submitted to the NRC Region 1 Office to verify that the details of the event were clearly reported, including accuracy of the description of cause and adequacy of corrective action, lne inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event war-ranted onsite followup.
The following LERs were reviewed:
Unit 1:
LER 88-06:
ESF Actuation Due to the Inadvertent Energization of Slave Relay K6429.
LER 88-07:
Reactor Trip and Safety Injection Oue to Reactor Coolant Pump Trip.
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LER 88-08:
Reactor Trip due to Low-Low Level in
"A" Steam Generator.
LER 88-09:
Reactor Trip and Feedwater Isolation.
LER 88-10:
Incore Instrumentation Thimble Tube Wear.
LER 88-11:
' Thermal Shield Bolt Replacement.
LER 88-12:
Feedwater Elbow / Nozzle Cracking.
Unit 2:
LER 88-08:
Notification of Deficiency in~ ITE-51 Time' Overcurrent Relays.
The above LERs were reviewed with respect to the requiremenes of 10 CFR 50.73 and the guidance provided in NUREG 1022.
Previous inspection repcrts have noted that while most LERs provided good documentation -of event analyses, root cause determinations and corrective actions, some LERs were weak in that they contained event inaccuracies and safety evalu-ation omissions. All of the LERs reviewed during this inspection period were found to be good.
LER report quality has been improving over the last several months. The inspector will continue to monitor LER report quality during future inspections.
12. Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 (Reporting Requirements) are reviewed.
The review assessed whether the reported information was valid, included the NRC required data and whether results and supporting information were consts-
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tent rith design predictions and performance specifications. The inspec-tor also ascertained whether any reported information should be classified as an abnormal occurrence. The following reports ~were reviewed:
BV-1/BV-2 Monthly Operating Report for Plant Operations for
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May 1-31, 1988.
BV-1 Revised Monthly Operating Reports for March and April, 1988.
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BV-1/BV-2 Monthly Operating Report for Plant Operations for
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Unit 1 Cycle 7 Startup Test Report.
No deficiencies were identified.
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13. Unresolved Items Unresolved items' are matters about which more information is required. in order to ascertain whether they are acceptable items, violations or
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14.. Exit Interview Meetings 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.on July 21, 1988.
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