IR 05000275/1987004
| ML20212M122 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/20/1987 |
| From: | Johnston K, Mendonca M, Narbut P, Padovan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20212M117 | List: |
| References | |
| 50-275-87-04, 50-275-87-4, 50-323-87-04, 50-323-87-4, NUDOCS 8703110104 | |
| Download: ML20212M122 (12) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION V
Report.Nos:
50-275/87-04 and 50-323/87-04
Docket Nos:
50-275 and 50-323 License Nos:
Pacific Gas and Electric Company 77 Beale Street, Room 1451 San Francisco, California 94106 Facility Name:
Diablo Canyon Units 1 and 2 Inspection at:
Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted:
December 28, 1986 through February 7, 1987
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Inspectors:
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L.M.Padovan,Residentypector Date Signed O.-
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. Johnston, Resident Inspector Date Signed
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P. P. Narbut, Senior esident Inspector Date Signed
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g- --- ff 7 eo Approved by:
M. M. Mendonca, Chief, Reactor Projects Section 1 Date Signed Summary:
Inspection from December 28, 1986 through February 7, 1987 (Report Nos.
50-275/87-04 and 50-323/87-04)
Areas Inspected:
The inspection included routine inspections of plant operations, maintenance and surveillance activities, follow-up of onsite events, open items, and LERs, as well as selected independent inspection activities.
Inspection Procedures 30703, 61702, 61705, 61706, 61726, 62703, 71707, 71710, 71711, 72700, 73051, 73702, 90712, 93702, and 94703 were applied during this inspection.
Results of Inspection:
No violations or deviations were identified.
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ADOCK 05000275 PDR
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1.
Persons Contacted J. D. Shiffer, Vice President Nuclear Power Generation
- - R. C. Thornberry, Plant Manager J. A. Sexton, Assistant Plant Manager, Plant Superintendent
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- J. M. Giscion, Assistant Plant Manager for Technical Services i
- J..D. Townsend, Assistant Plant Manager for Support Services
.D. B. Miklush, Maintenance Manager
'R. M. Nanninga, Maintenance Engineering Supervisor W. G. Crockett, Instrumentation and Control. Maintenance Manager t
- L. F. Womack, Operations Manager
- T. L. Grebel, Regulatory Compliance Supervisor S. R. Fridley, Senior Operations Supervisor
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- R. S. Weinberg, News Service Representative
D. A. Malone, Senior I&C Supervisor The inspectors interviewed several other licensee employees. including
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Shift' Foreman (SFM), reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, quality assurance personnel and general construction personnel.
- Denotes those attending the exit interviews on January 16 and February 6, 1987.
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2.
Operational Safety Verification a.
General During the inspection period, the inspectors observed and examined activities to verify the operational safety of the licensee's facility.
The observations and examinations of those activities were conducted on a daily, weekly or monthly basis.
On a daily basis, the inspectors observed control room activities to verify compliance with selected Limiting Conditions for Operations
.(LCO::) as prescribed in the facility Technical Specifications (TS).
Logs, instrumentation, recorder traces, and other operational records
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were examined to obtain information on plant conditions, and trends
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were reviewed for compliance with regulatory requirements.
Shift turnovers were observed on a sample basis to verify that all pertinent information of plant status was relayed.
During each week, the inspectors toured the accessible areas of the facility to observe the following:
(a) General plant and equipment conditions.
(b) Fire hazards and fire fighting equipment.
(c) Radiation protection control }'w
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(d) Conduct of selected activities for compliance with the licensee's administrative controls'and approved procedures.
(e)
Interiors of electrical and control pane?s.
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(f) Implementation of, selected portions of the licensee's physical security plan.
'(g) Plant housekeeping and cleanliness, n
(h) Essential safety feature equipment alignment and conditions.
The inspectors talked with operators in the control room, and other
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plant personnel.
The discussions centered on pertinent topics of general plant conditions, procedures, security, training, and other aspects of the involved work activities.
'No violations or deviations were identified.
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3.
Chronology of Significant Iten's
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a.
On January 1 while attempting to place the turbine -in load control (from speed control), the turbine controls ~ acted erratically causing steam generator level swings.
This is discussed in detail in paragraph 4.c.
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.b.
On January 2, 1987 a turbine oil fire occurred in Unit 1.
This is
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discussed in detail in paragraph 4.a.
c.
On January 5, 1987 the Unit I reactor tripped from 33% power..This was due to leaking turbine electro hydraulic' fluid causing the turbine valves to go shut in turn causing a unit trip, reactor trip.
A complication was encountered during manual transfer of electrical power from auxiliary to startup power sources.
This is discussed in detail in paragraph 4.b.
d.
On January 10 a second smaller smoldering oil incident occurred in Unit 1.
This is discussed paragraph 4.a.
e.
On January 12 and again on January 13, the Unit 1 rod control system was placed in automatic with portions of the rod control system not energized or in test mode.
This is discussed in detail in paragraph 5.a.
f.
On January 13 the isolation valve for auxiliary saltwater cooling to the component cooling water heat exchanger wouldn't close.
This is discussed in detail in paragraph 5.a.
g.
On January 16 there was a water hammer event on an Auxiliary Salt Water System caused by biofouling of vacuum breaker valve SW-2-303.
The licensee investigation showed no damage was incurred from the event.
The event occurred during testing of the system.
The licensee is investigating corrective action to prevent recurrence.
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During testing on January 17 the diesel generator 2-1 circuit breaker
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my to 4kv bus G'would not trip electrically (either locally'or at the
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remote location).
The breaker was manually. tripped'at the L
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switchboard.
Subsequent investigation determined a loose wire was
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the probable cause.
The licensee corrected the situation but-x
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'w deferred further corrective action based'on successful testing and
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planned breaker maintenance during the Unit 2 refueling outage.
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On Jar,uary 18 Unit 1 went into a rapid power reduction from 96% power to 50% power due to a loss of lubricating oil from main feed pump h s s-0-2.
'This is discussed in detailLin paragraph 4.c.
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09 January 21,-Main Feed Pump 1-2 was determined to have a wiped bearing which was discovered.during attempted startup after the
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4.
Onsite Event Follow-up.
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a.
Unit'1 HP Turbine Insulation Fire
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At 1742 hours0.0202 days <br />0.484 hours <br />0.00288 weeks <br />6.62831e-4 months <br /> (PST), on Jan'ary 2, 1987 the licensee declared an u
Unusual Event due to a small fire near the Unit 1"high pressure turbine bearing.
The California Department of Forestry (CDF), as specified in the licensee's emergency plans, was called in at 1742
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hours to extinguish the fire. 'The licensee, as a conservative measure, brought the reactor'subcritical at 1927 hour0.0223 days <br />0.535 hours <br />0.00319 weeks <br />7.332235e-4 months <br /> after a Xenon.
transient caused by the decrease in power from 33% to 8% reduced the stability of'the reactor.
The main turbine was shutdown to facilitate extinguishing the fire.
The fire was due to oil soaked piping insulation being ignited by high temperature steam piping. The licensee determined the oil to be turbine bearing lube oil from two possible sources.
The first
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possibility is that lube oil flowed past the front bearing due to a s.
higher than normal lube oil system pressure.
The second possibility is that during'the Unit 1 refueling outage spillage occurred during 1f the lube oil flushing activities of the Unit I refueling outage.
i Three auxiliary operators experienced heat exhaustion during the initial fire fighting efforts prior to the arrival of the CDF.
Two were treate'd on site and the third was treated at a local hospital.
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All were released that evening.
The heat exhaustion was attributed to the high ambient temperatures inside the high pressure turbine housing.
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~ Prior to restart, the licensee removed the oil soaked insulation in the area immediately surrounding the fire.
Due to the relative inaccessibility and high ambient temperatures of the area of the fire, the licensee was unable to perform a thorough analysis of the oil soaked insulation.
They did perform a piping integrity inspection and determined that the heat of the fire and the relatively cold water used to extinguish the fire had not damaged any adjacent steam line...
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An Unusual Event was declared when the licensee notified the CDF.
The emergency plan required that the CDF be notified if a fire is not
under control within 10 minutes.
Under the emergency plan, the County Sheriff is to be notified within 15 minutes of a declaration
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of an Unusual Event.
The County Sheriff was not notified for t
approximately one-and-one-half hours.
This issue is the subject of a g
separate inspection report and violation 50-275/87-06).
On January 10, 1987 a second smoldering oil incident occurred in an area adjacent to the first fire.
In this case the smoldering
i occurred on the high pressure turbine insulation.
The fire was quickly brought under control by auxiliary operators, an Unusual
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Event was not declared and the Unit remained at power.
Again, the I
fire was due to oil on the insulation ignited by the Ligh
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temperature of the turbine casing.
The licensee determined that the source of oil was the same as the first fire.
Following the second
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fire, a more extensive removal of insulation was performed.
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Since they established two possible sources of lube oil, the licensee took two separate actions to prevent recurrence. With regard to the possibility that lube oil flowed past the front bearing due to a
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e higher than normal lube oil system pressure, the oil pressure was I
reduced, the oil seals were inspected and verified to be in proper working order and no oil seepage was observed during subsequent turbine operation. With regard to the possibility that the oil was spillage from the Unit 1 lube oil system flush, a memo has been J
issued to all personnel detailing the need to report oil spillage i
that could lead to a potential fire.
This subject has also been
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incorporated into General Employee Training.
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b.
Reactor Trip Due to Loss of Turbine Governor /Stop Valve Electro-hydraulic (EH) System Pressure
E E
On January 5,1987 while ramping down from 33% power.in response to I
low EH control fluid level, Unit 1 experienced a unit trip, turbine
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trip, and subsequent reactor trip due to actuation of a generator y
anti-motoring relay. The low EH control fluid level was causeri by
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leakage from a compression fitting connection to the hydraulic
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actuating arm on #3 steam lead high pressure turbine stop valve
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FCV145. When low level was reached in the EH reservoir, the EH pumps
tripped and EH fluid pressure rapidly decreased.
The turbine E
governor and stop valves drifted closed, and the resulting decrease
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in steam supply to the turbine created a low pressure differential across the high pressure turbine (sensed by pressure switch PS-30).
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PS-30 started a 30 second timer in the anti-motoring relay circuit, which then initiated a unit trip, separating the generator from the zI grid, tripping the generator field, auto-transferring electrical R
buses D, E, F, G, and H, and creating a turbine trip signal.
The turbine trip occurred at greater than 10 percent power, so permissive r
g P-7 allowed a' reactor trip signal to be generated.
Appropriate
emergency procedures were followed, and the plant was stabilized in E
Mode 3.
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, a sPriorft'.o'the[ unit; trip,3 a : low level alarm was receiv'edLon t'hs'EH'? ' f
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u ystem oil reservoir.' ' Operators responded'toIthe alarm 5and found the,~
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. e W S reservoir to be-about 5/8 full.
EH system components located near
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-also examined the: area in the " dog-house'haround the high pressure.
Tthe' reservoir were inspected for signs;of' leakage, andtan~operatori i
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turbine (containing the leaking ~ fitting) but~couldlnotalocate the N
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, leakage.. An auxiliary operator was then : informed ~'of. the needf to
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Q l refill the reservoir before the 'e'nd of,the shifta Eventually,1th'e=
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- reservoir low l level EH pump, lock-outipoint.was reached,.at'which ' time V N.
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operators manually held the-lockout in'theireset position.to allowy 7
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" time to. fill the reservo_ir..cShortly after the power rampdownibegan,;-
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stripping;the EH pumps and causing the' turbine valves:to-drift closed.'
.the EH low level. lockout relay began to smoke *and.had-to beireleased,-
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The. leaking fitting on the hydraulic actuator was examined by the
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licensee and was determined to'have been originally a'ssembled..
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- licensee conc 1 dsd the fitting most likely had been'
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disturbed during fire fighting'and subsequent cleanup activitiesiin
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in the area earlier in the'weekt.a All other EH. system fittings were i
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then checked and were found to be properly installed and. tight.
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During the.rampfdown in power, operators manually transferred the
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'startup power source. Vital bus G tripped on overcurrent. ' Diesel
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generator 1-2 automatically started on bus G undervoltage.but
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' correctly'did not load due to the bus-trip overcurrent lock.out
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protection feature.
Bus G remained dead for'about two hours while
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the overcurrent condition'was evaluated. The licensee's
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investigation:into the overcurrent trip on bus G determined the
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C auxiliary to,startup transformer transfer scheme permitted the
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' auxiliary power network to be paralleled with the startup power
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- network. for. a. greater period 'of time than normal.
As these twoD
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networks normally vary in: voltage about 150 volts, the paralleling.of
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tthese systems for~too long-attime period created the uvercurrent.
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_ condition on bus G.
Normally, during manual transfers of the 4160
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' : breaker is momentarily closed onto the bus at the same time the
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auxiliary power breaker is closed onto the' bus. When the startup
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breaker closes, an auxiliary switch on that-breaker also closes to E send a control. signal to the auxiliary power breaker to trip open.
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" However, this. control signal is routed through contact G on the n4 control room transfer switch, which must be in the transfer-position to permit'.the signal to reach the trip' mechanism of the auxiliary
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power breaker.
The-licensee concluded.the operator released the transferiswitch at'a' moment in time which permitt'd the startup e
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- 7 breaker to close'but' interrupted -the signal from the startup breaker
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auxiliary switch to open the auxiliary power source.
This paralleled s
it the power sources until both bus G power sources tripped on-
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l-M overcurrent.
In reaching this conclusion, the licensee investigated E
'the possibility of transfer switch overtravei, checked the auxiliary
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breaker trip coil:and startup breaker auxiliary switch, t
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unsuccessfully attempted to repeat the occurrence, and obtained i
engineering evaluation of the situation.
No mechanical or~ electrical
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problemsLwere. identified.
The scenario presented by the licensee requires the switch to have been: released during a 10 millisecond-window during the transfer of power sources. The scenario is a possible explanation but'is discomforting in that the probability of'
releasing the transfer' switch in that very short time window is very low.
The inspector found no fault with the licensee's examination of alternative possible causes but cautioned the-licensee to ensure that allLalternatives were well thought-out, and thoroughly examined.
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Digital Electro-hydraulic Control System Malfunction-On January 1,1987 with the Unit 1 main' turbine spinning at 1800 RPM
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in speed control,.the operator parallele'd the generator to the grid by manually closing power circuit breaker PCB-532-in'accordance with,
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operating procedure (0P) C-3:II," Main Unit Turbine.Startup.", As
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expected, the digital electro-hydraulic, control.(DEHC). system
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automatically positioned the governor valves to pick up about 5%' load (65 MW electric).
Pursuant to OP C-3:III " Main Unit Turbine-Load Changes" (with the DEHC system in " operator auto"),'the operator depressed the DEHC " load rate" button and entered a lo'ad rate of change of 1 MW per minute. -Then,.by'depres' sing the " reference" button,'he entered 100 MW as the final megawatt load desired.
The operator next pressed the "go". button expecting the load to be
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automatically changed at the preset rate until it reached the referenced value., However, upon pressing the go button,'the. operator noticed the power factor meter moved toward the " lag" position and steam generator levels began to swing.
Subsequently, the operator observed that the DEHC reference window indicated "15" and demand'
-(actual load) registered "0".
At that point, the operator tripped the output., breaker PCB-532, separating the generator from the grid,
' returning the DEHC system to speed control, and stabilizing the-plant.
Information, which was then called up from the DEHC control panel, displayed a load rate of 300 MW per minute and a reference speed of.3800 RPM, with a.2080 RPM per minute ramp rate.
Ac,tual turbine speed remained at 1800'R@i, however.
The planned load increase'was curtailed, and an investigation into the functioning of the DEHC system was initiated by the licensee.
The licensee's investigation determined the DEHC load control (software) program.had been previously disrupted without the licensee's knowledge. Apparently, during recent troubleshooting of a turbine stop valve, the single valve was cycled opened and closed while the DEHC was in speed control.
Normal exercising of the stop valves is performed with the. turbine at rated speed in load control
.in accordance with STP M-21C " Main Turbine Valve Testing." The inspectors will' perform follow-up review of the appropriateness of troubleshooting the valve while the DEHC was in speed control.
(0 pen-Item 50-275/87-04-01).
d.
Unit 1 Main Feedwater Pump Coupling Housing 0-Ring Failure On January 18, 1987 a large leak developed in the.1-2 main feedwater pump coupling housing.
The operators responded by ramping the unit
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form 96% power to 50% power at 50 MW per minute.
This was done in
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~an! anticipation'ofLa possible'sain feedwater pump trip on?lollo lube
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i oilglevel. ?The operators; managed.t'o take;the pump off011neJand placeL "
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fit,on a-turning gear before a-lo lo>1ube oi.lilevel was' reached.~'
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- 'In'spection of>the; pump dele'rm'ined 5' hat lthe coupiingihousing 0-fing '
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~had failedfand the. action 1o_f the pump: shaft'had. slung, oil outithe
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- gap.f-The" licensee' speculates thatethe 0-ring had been pinched ^during
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'and thelpumpswas'placed i_n se(couplingi JA newj0-ring washinstalled.
theithermal? expansion of;the
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~Noivio1ations'orfdeviations'were' identified.
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The inspectors l observed p.ortions of, and reviewed records.'on', selected -
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-maintenance activiti~es'to assure compliance ~with approved procedures,
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'technica11 specifications, and appropriateiindustry codes ~and standards.,
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Fu.+.hermore,' the inspectorsLverified maintenance activities were' performed
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by qualified pers'onnel, in accordance with-fire protection and
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housekeeping controls, and. replacement parts were appropriately certified.
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. Unit I?- Auxiliary Saltwater FCV-602
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Theiinspector witness'ed' portions of a corrective-maintenancei c
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performance on 1-FCV-602, the Unit 1 auxiliary saltwaterjinletf
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y isolationjvalve ;to the component cooling water heat exchanger.. The
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corrective maintenance followed the~ quarterly performance.of STP_ '-
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P-78, "Routir.e Surveillance Test' for Auxiliary Saltwater Pumps;"'
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During the STP FCV-602 did not fully open'when: cycled. When the-
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- valve failed to fully open, the train was? declared inoperable,
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. initiating a. 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS action statement, (TS 3.7.4.1." Auxiliary
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" Saltwater.. System"). 'The' inspector observed the' initial < attempts to',
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lubricate the valve actuator. -When this did not eliminate ~the
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problem,fmaintenance inspected the valve body internals'and#
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sdiscovered biofouling.
Maintenance cleaned.the' valve and.again-the'
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. valve' failed to~ stroke freely.. -Maintenance greased the valve
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factuator bushing and operated the valve successfully.
The inspector-
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available during the maintenance, the proper administrative * approvals-
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l-and tagouts were obtained, andithat the maintenance was performed in
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a methodical,1contro11ed manner.
Mechanical Maintenance initiated a-
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the component cooling water heat exchanger for monthly stroke
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e testing..In addition, a preventive maintenance program is to be
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implemented to lubricate the valve actuator bushings.
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'The. subject' valves were not previously included in the preventive
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maintenance program.
The licensee has depended on stroke time p~.
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trending to track the degradation of many safetyrrelated pneumatic'
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?f actuated valves.
However, the subject valve failed prior to its
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. scheduled stroke' testing, which was performed the day fo110 wing'the
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performance of STP P-78.
Therefore, the inspector questions the
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, effectiveness of the present surveillance program for: identifying
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i" the' maintenance problem.' The? inspector will perform a follow-up t J
~' review of-the above concern-(0 pen Item 50-275/87-04-02).
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1bl-ControO Rod Au'tomatic Control System 1-
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.On January 12,01987 at 1740 hours0.0201 days <br />0.483 hours <br />0.00288 weeks <br />6.6207e-4 months <br />, while Unit 1 was-atfapproximately-
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selector switch from manual'to automatic.t The automatic control:
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function circuitry at that time had two control modules de-energized
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-and a third had its normal. input removed and was receiving a-test'
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signal.. 'In this condition the reactor, power.- turbine power rate-
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comparator portion ~of the logic would not have reacted to a' power-
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. mismatch. 'Thisi condition was not recognized by the operators. On
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< January 13, 1987 at 0945 hours0.0109 days <br />0.263 hours <br />0.00156 weeks <br />3.595725e-4 months <br /> the' control operatorsiagain put the
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. control rods in-automatic control'at which time Bank:0 promptly.
steppe'd.out at:72 steps / minute'. The control operator recognized this-
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as being an abnormal response and returned the control rods to:
-manual. These" events were-a result"of the operations unaware that:1&C work on the control rod. automatic con, staff being 7'
trol.: system had not been completed.
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Background
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In March,:1986 the control rods exhibited' unwarranted motion;(i.e.
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4the rods would.noveLwith a;0.1Edegree: temperature deviati'n where it-
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is' designed to not move until'there is'a~1;5 degree deviation).and an Action.-Request was initiated.. At that time'the respon'sible I&C
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foreman determined that the.necessary troub_leshooting would have.to.
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be performed'with the unit shutdown. : When theJtroubleshooting was
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' performed in December,-during.the unit's sfirst refueling outage, no
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j problems were found and the issue.wasiclosed. On January 2, 1987 the
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- unwarranted rod motion reappeared and another Action Request was
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, initiated.
This time.it was determined that-troubleshooting could be
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performed at power with the' control rods-in manual. 'I&C initiated work on January 9-by obtaining the shift foreman's4 verbal. permission-as required by the: Work' Order package and. operations placed an y
information tag.on the control bank selector switch.
A formal clearance was not issued for this work (by the administrative procedure a clearance was not required).
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On January 12, the I&C technicians discovered the faulty. module and
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replaced it. They continued to perform a channel calibration until.
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their shift expired at the end of. day' shift. The information that the; faulty module had been replaced was verbally relayed from _the a'
. technicians to their foreman to the I&C General Foreman to the
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Operations Manager.
In this verbal chain the fact that the I&C technicians had not completed a channel calibration test was lost.
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The Operations Manager told the Unit 1 control room staff during the turnover.to swing shift that the automatic control function had been
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repaired.--The control room staff " confirmed" the operability of the
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automatic control function by placing the system into automatic and noting a control rod response to a T(AVE) - T(REF) mismatch of 1.6
' degrees.
At this time " Info" tag was removed by operations personnel
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'(who had hung the tag originally).
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The dayishift on January.513 received word /during their_ turnov'er. that
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the automatic. control function had.b'een repaired and was operable..
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,At approximately.0830 hours0.00961 days <br />0.231 hours <br />0.00137 weeks <br />3.15815e-4 months <br /> the I&C technicians returned to complete'
the channel calibration test.
At 0945 hours0.0109 days <br />0.263 hours <br />0.00156 weeks <br />3.595725e-4 months <br />, when the control troom'
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. returned to automatic control, the I&C technicians were~ injecting C : test sig'nalsito a :1ead/ lag module, which caused the ' rods to step out
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rapidly.1The operators quickly returned the control rods to manual
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Jcontrol and avoided a transient..An " Info" tag was again hung on the control - switch'. When'the loop calibration was completed, the I&C-technicians reported-to the shift-foreman, as required by the Work
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Order and the-Info tag as removed.
The inspector' discussed with licensee management the safety..
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significance'of having the~ power mismatch portion of the automatic
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control function disabled without the operator's knowledge.
The,
. licensee' stated that this condition is. bounded by the FSAR' accident
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analysis.which considers uncontrolled rod withdrawal with the reactor at full; power.
The analysis shows that a number of reactor trips will occur before any safety limits are exceeded.
However,.with the
< power mismatch portion of the automatic control function disabled the control. rods would have responded differently to a plant transient
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than the operators would have expected.
It is conceivable that an
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unwarranted reactor trip may have occurred, unnecessarily challenging
, safety systems.
Although the rod control system is not a safety related system, it-is a system important to plant operation and
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. operations personnel should be aware of its status at all times.
The licensee agreed with'the inspector that the controls used for the
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maintenance performed on the. rod control system were inadequate.
- Specifically, passing verbal information on the status of completion
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from.the " doer" to the." user"'is insufficient control of important'
equipment. Administrative Procedures C-6 and C-7, which provide guidance on clearances and tagging, are ambiguous with regard to
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systems that must'be energized during maintenance.
The licensee has committed to revise these procedures to delineate what work
- requires clearances and what tracking and tagging systems are applicable in those situations where a. clearance is not applicable.
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For this example, a work order would require a shift foreman's concurrence prior to the start and after the completion of work.
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. addition, the caution tag would be both placed.and remosed on the rod
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-bank selector switch (stating that the rods could not.be placed in
automatic) and providing the Work Order tracking number by the
" doer",'the I&C technician responsible for the tag.
The revisions to Administrative Procedures C-6 and C-7 will be reviewed by the inspector. (0 pen Item 50-275/87-04-03).
A second more general' issue highlighted by this event is the. apparent tendency on the part of licensee personnel and administrative systems
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to accept verbally passed information as fact (sometimes through a
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chain of people).
In this event, an information tag was both hung
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.and removed from the control: room rod conteol-switchi_byt operations >f
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through.al chain'of, people. 5 Previous:eventsoindicate:this is.not an~
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sisolated tendency.
Report,50-275/86-29; described la containment door -
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t on Augusti30, 1986 foundnothing'wrongand.fixednothing,butjariods_
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' people-recorded fictitious actions he^ supposedly tooks _ based on'
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'Likewise, in the case-of the oilismoldering Lfire of-/ January 2,l2987..
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'several conclusions:were drawn from: verbal 4 accounts of,someonelhavingo
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. -out the_ person saw liquid droplets but did not" determine whether-the 1seen oil sprayin' from-theLbearing journal. housing. -It later turned
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Jon-the " fact"~that= oil spray caused _the~ oil! fire.
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.The apparentiindications that licensee personnelLand< administrative
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systems accept" informal communications -in' inappropriate circumstances
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<willebe.followed up in future inspections 1(0 pen Item
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'50-275/87-04-04)..
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' Surveillance
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y By direct observation and record review of selected ~suiveillance testing,
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' the inspectors' assured compliance with,TS requirements and plant',.
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- procedures. The inspectors verified that test equipment was calibrated; M_N
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. and acceptance criteria were met or appropriat'ly dispositioned.
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Calibration of Unit 2 Boric Acid Storage Tank Level Channel 106
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The inspector. observed portions' of'the' calibration of the level
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transmitter on.the' Boric Acid Storage' Tank-2-1 (BASTc2-1). This
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' with boric acid coming out of-solution and~ depositing on the the
. lower leg pressure-bellows..The' inspector observed that proper
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stagouts were made and' administrative approvals obtained. The testing q
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was used.
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- Operation of' Safety Injection Slave Relays KG04 A & B t
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The i_nspector witnessed the performance of STP M-16B " Operation of
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Slave Relays KG04 A and KG04 B for Unit 2. -The performance.of this-A.-
test satisfied the quarterly safety injection slave relay test
~~ < r c requirements.of TS 4.3.2.1.
In addition, since it re6 ires the,
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. actuation of general safety related components, STP-M-16B' satisfies
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portions.of 'other TS sections, i.e. TS 4.8.1.1.2.b.6, the.18 month x
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test of the emergency diesel generator auto-start onEa. safety',
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- injection test signal.
The surveillance was performed using a revised procedure which incorporates _the_ checkoff list into the body
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.of the procedure. The revised procedure eliminates ths redundancy of
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having 'a separate. checkoff list.and.,is e,asiersto'f6110w.".The; -
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! surveillance.was performed bysthe# Unit 2fcontroltroom stafft
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After the
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ftesting was1 performed the systems were properly. returned to. service.
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. 71 ' 'Folliw-up'of Headquarters ' Requests.
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I Grads'8 Bolts'
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In-November,'1986,;in response to concerns of. counterfeit bolts,-the.
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. Vendor ProgramsLBranch of the Division of Inspection and Enforce'nent
requested the licensee ~to supply a~s' ample.of' ASTM-A-354 grade l8 bolts
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for,chemicaltanalysis and tensile-testing.
0f'the three bolts-.the:
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- licensee provided,1none were found.to be counterfeit...However,Eone-
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bolt failed the' tensile test by.approximately 10L The. licensee has-
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- proposedsto= tensile test an additional two bolts.
The.sampleEsize-isi
,in accordance with ASTM guidance for the failure of one bolt ofia'
L controlled lot of bolts manufactured from the same batch of material.
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The results of'this t'esting will'be followed up by the inspectors,as.
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Lopen item (50-275/87-04-05).:
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~ D No violations or deviations were^ identified.
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(8. J Licensee Event: Report Follow-up
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1 Based on aniin-office! review, the following LERs were closed out by-the
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resident ' inspector:
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- Unit'1:
'87-01, 85-41,f86-08 TheLERswerereviewedforeventdescription,rootcause, corrective W -
' actions taken,; generic a'pplicability and timeli' ness of reporting.
LER
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~87-01 was found to' incorrectly designate FCV 143 as,the leaking turbine
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- stop valve.
The LER should have indicated FCV 145 was the turbine stop:
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i f valve' withithe. leaking fitting.
As all turbine:stop. valves'are_similar, a
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, ye-revision to-the.LER is not-warranted.
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N'o violations;or deviations were' identified.
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. On Febru'ary 6',1987. an exit medting was con' ducted with the licensee's. _
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1 representatives identified in paragraph l a The inspectors summarized the scope and. findings of the inspection _as'describedjin:this rep' ort.
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