IR 05000317/1988017
| ML20207B245 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 07/21/1988 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20207B237 | List: |
| References | |
| 50-317-88-17, 50-318-88-17, NUDOCS 8808020282 | |
| Download: ML20207B245 (11) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report:
50-317/88-17 License:
DPR-53 50-318/88-17 DPR-69 Licensee:
Baltimore Gas and Electric Company P. O. Box 1475 Baltimore, Maryland 21203 Facility:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection at:
Lusby, Maryland Inspection conducted: June 27 - July 13, 1988 Inspectors:
D. Trimble, Senior Resident Inspector V. Pritchett, Resident Inspector Approved:
N_
h L. d. Tripp,
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J
ate
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Reactor Projects Saction 3A
.S um:-a ryl June 27 - July l j988:
Special Inspection Report Nos.
50-317/88-17,50-318/88-17.
Areas inspected:
Special resident inspection of (1) a June 4,1938, event involving the inoperability of a diesel generator due to operator error and (2) a July 4, 1988, event involving an improper.1%ustfrent of dif ferential temperature (AT) power.
Results:_
An operator error in leaving a diesel generatur (DG) voltage regulator in the i
manual mode caused the inoperability of OG #21 for a 48-hour period.
This is
an apparent violation (detail !).
Operator error in making an adjustment to dif ferential temperature ( AT) power without first having a calorimetric l
reference power available may possibly have caused reactor protection system limiting safety system settings to be exceeded (detail II).
Both events, as well as a March 30, 1988, event in which pressurizer /prenurizer spray line i
differential temperature was exceeded, indicate that Operations persnnnel are not rigorously following procedure, nor are they maintaintng a sufficiently questioning attitude (detail III) during attempts to resolve ongoing problems.
800 !!!g m @onu no a
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DETAILS Within this report period, interviews and discussions were conducted with various licensee personnel, including reactor operator s, maintenance and surveillance technicians and the licensee's managenant staff.
I.
Overview of Emergency Diesel Gererator Event (93702)
A.
On June 4,1988, Unit 2 was operating at 100% power and the #21 emergency dierel generator (EDG) was being tested to satisfy surseillance requirements.
The testing required Operations to start and parallel the diesel to an offsite power source on engineered safety features (ESF) bus #24.
The EDG output breaker tripped due to reverse power on each of three attempts to close the breaker.
Operators assumed a malfunction in the diesel generator's automatic
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voltage regulator and placed the voltage regulator in the manual mode t
in order to complete the test.
The testing was compl9ted; however, the voltage regulator was not returned to the automatic mode.
This action rendered #21 EDG inoper:ble in that it would not successfully power essential loads as required.
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On June 6,1988, during the performance of another surveillance test on #21 EDG, Operations personnel determined that the diesel performance was unsatisfactcry and concluded that, while the voltage
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regulator was in manual mode, #21 EDG was inoperable.
Failure of Operations personnel to recognize the significance of placing the
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voltage regulator in the manual mode on June 4, 1933 resulted in Unit 2 entering a Technical Specification action statement unknowingly and resulted in the failure to perform required redundant equipment surveillance testing.
B.
System Description and Requirements
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1.
Eme+3ericy Diesel Generators
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i The emergency diesel generators (EOGs) provide a dependable on-
site power source capable of automatically starting and supplying the essential loads necessary to safely shut down the plant and maintain it in safe shut down under all conditiens including a loss of coolant accident (LOCA).
Two EDGs are required for both units to supply minimum power requirements for engineered safety features equipment.
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requirements are fulfilled by one dedicated EDG for each unit and one swing redundant EDG which can supply either unit.
2.
Reguirements Technical Specification limiting condition for operation (LCO)
a 3.8.1 1 specifies the minitrum AC power sources which must be operable during Modes 1, 2, 3 and 4.
LC0 3.8.1 lb requires
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that two separate end independent EDGs be operable.
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Action statement "b" of LCO 3.8.1.1 allows one of the EDGs to be inoperable for a maximum of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided the operability of the remaining AC power sources is demonstrated by performing:
(1) surveillance requirement 4.8.1.1.la (500 KV off site power breaker alignment check within one hour and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter), and (2) surveillance requirement 4.8.1.1.2,a.4 (start test of the remaining EDG within 2t hours).
C.
Detailed Description At 11:13 on June 4, the #21 EDG was test started in accordance with Surveillance Test procedure STp-0-7-1.
By procedure, the EDG was then to be paralleled with offsite power and run for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> under load.
Following synchronization and paralleling of the EDG with off-site power on 4rV ESF bus #24, reactive load increased rapidly.
The EDG output breaker tripped open on reverse power at about 1000 KVARS (lagging) inoicated.
The evolution was repeated two additional times with the same result.
The apparent cause of the problem was that the operator performing the paralleling was not rapidly loading the EDG to 300 KW immediately after paralleling as required by Operating Instruction OI 27C, Revision 9.
That operator, and other control room personnel who came to assist him after the first failure, focused on the unusual increases they were seeing in reactive load and did not recognize the apparent true cause of the reverse power i.e., lack of loading of the EDG.
The shif t supervisor (SS) was notified after the three failures.
The SS and control room supervisor (CRS) discussed the problem and concluded that the voltage regulator was degraded when in the automatic mode with the EDG operating in parallel with another generator. A maintenance request (MR) was initiated.
They believed the voltage regulator would function satisfactorily in automatic in a post-accident condition because in that case the EOG would not be required to operate in parallel with other generators.
Therefore they considered the EDG and auto voltage regulator to be operable.
This telief, at least in part, appears to be due to a training deficiency.
They very clearly recognized the effects of voltage regulator adjustments in changing reactive load on the EDG when operating in parallel with offsite power, and they routinely make those adjustments.
They rarely see the situation in which a EDG is the sole generator on a bus.
In the latter case, the amount of reactive load on the EDG is determined by the equipment running on the bus and not by varying voltage regulator output.
They recognized this and apparently mistakenly attributed less importance to the i
voltage regulator in the sole source situation. What they did not consider was that, as an incicasing number of loads are sequenced on to a bus, as would happen in a post-accident condition, apparent, true, and reactive power requirements increase (even though the power factor may not change).
Therefore, greater I
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amounts of exciter current must be provided by the voltage regulator to the generator field to increase reactive power output from the generator. Otherwise bus voltage will successively decrease as more
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loads are applied to the bus.
Eventually, voltage would reach a
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minimum value at which bus undervoltage protection devices would l
actuate to open the breakers for bus loads.
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The SS decided to complete the one-hour DG loaded run by placing the voltage regulator in manual.
This was done and the EDG was
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successfully paralleled with offsite power at 11:30 a.m.
A temporary change to 01 27C should have been made in accordance with Technical Specification 6.8.3 but was not performed.
The SS intended that the voltage regulator be returned to auto after the run.
The run was completed at 12:30 p.m. and the EDG was shutdown.
Due to a comunications problem, the control room operator thought that the voltage regulator auto mode was out of service He left the regulator selected to manual and noted in his log that the #21 EDG regulator auto mode was out of service.
Operations management personnel believe that operators on the following shifts may not have recognized improper voltage regulator
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selection, probably oecause they were accustomed to seeing the main turbine generator voltage regulator selected to manual with no apparent adverse effects.
The EDG and main generator differ in that the main generator does not experience large loading transients and the main generator manual voltage regulator tracks the auto voltage regulator.
At 10:56 a.m. on June 6, #21 EDG was test started in accordance with STP-0-88-2.
The EDG accelerated properly to rated speed but required an abnormally long time (29.4 seconds) to reach rated output voltage (rated output voltage usually occurs within 9 seconds and about 1 second after rated speed).
(Technical Specifications do not specify l
a maximum time limit for reaching rated voltage.
TS do specify a limit of 10 seconds for reaching rated speed.) The voltage regulator was returned to auto at 11:09 a.m. and the test was satisfactorily
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completed (reached rated speed and voltage within 8.1 seconds).
A subsequent engineering analysis showed that, with the value of
excitation current that would have been provided to the generator during the period the regulator was selected to manual, in the event
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of a loss of coulant accident concurrent with a loss of cffsite power, the following would have occurred:
(1) the #21 EDG would have started and closed onto #24 bus at 29.4 seconds, (2) the initial loads that would apply immediately on breaker closure would have l
caused a decrease in output voltage to just ovce 75*. of rated voltage (4160 VAC), (3) the firs *, of six sequential load steps would have been applied at 34.4 seconds, and (4) without operator action, l
output voltage would at this point have fallen to a value where bus loads would have shed automatically by degraded voltage circuitry i
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4 which protects equipment motors from damage due to overcurrent heating.
EDG #21 was therefore inoperable during the 48-hour period the voltage regulator was in manual. During this period, the checks and testing required by TS 3.8.1.1.b Action b. (500 KV off-site power breaker lineup check and test of alternate diesel) were not performed because EDG inoperability was not recognized.
Since they were not performed, the TS limiting condition for operation (LCO) was exceeded.
O.
Regulatory Concerns and Issues Assumption by operators that #21 Emergency Diesel Generatw was
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operable when, in fact, it was not operable.
This resulted in
the Technical Specification 3.8.1.1 b LC0 being exceeded.
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Adequacy of controls allowing operators to proceed beyond
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operating instructions without observing procedure change protocol end without first soliciting assistance from technical
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support personnel.
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Lack of positive questioning attitude by operators when
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confronted with an abnormal situation.
Adequacy of training in allowing operators to operate an
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emergency diesel generator without proper knowledge and/or training on the significance of placing its voltage regulator in
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the manual mode.
II. Overview of Nuclear Instrument / Delta T Power Event (93702)
A.
During a startup of Unit 1 on July 4, 1988, with the plant at cbout 12?4 power, control room personnel noted a 5?; mismatch between two types of indication of plant power. Nuclear instrumentation (NI)
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I power indicated 17% and reactor coolant system (RCS) differential
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temperature (AT) power indicated 22%. A control room operator with i
shift supervisor approval tried to resolve the mismatch using an j
improper means. Without having calorimetric information available as a point of reference for true power (due to a plant computer problem), the operator incorrectly assumed that NI power indication was more accurate than AT power.
He then adjusted AT power on all j
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four instrumentation channels to match NI power.
Such an adjustment,
without first obtaining calorimetric information, was a violation of procedure.
Subsequent evaluation showed that, in fact, the original i
AT power was the more accurate power indication.
Because Operations personnel were uncomfortable with the situation of not having calorimetric data available as a power reference, a decision was made to perform a hand calorimetric at the first plateau in the power escalation procedure which was the 30% power
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l point. At the 30*4 indicated power point, the calorimetric showea that true (thermal) power was actually 44%.
Therefore, NI and AT power were non-conservatively reading 14*4 Imer than true puwer.
B.
System Description and Requirements
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i During power operation, two types of power indication are monitored by the operator and each of four channels of the reactor protection system (RPS) for e nigh reactor power trip.
They are nuclear instrumentation (NI) power (from uncompensated ion chambers) and AT power.
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In each RPS channel NI power and AT power are auctioneered, and the higher of the two is selected as core power.
This core power is
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designated "Q" power.
"Q" power is then compared to a variable high
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power trip limit signal (Qa.r).
The maximum Q is 107*4 and minimum tr
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is 30*4.
Q is a function of Q and its past history.
As Q decreases, the gp limit signal Q also decreases but remains above Q by a fixed trip tr margin. When Q increases O remains at the minimum value gp previously achieved until reset by the operator. When reset, Qgp increases to the same fixed trip margin above Q as existed prior to l
resetting.
Reset is accomplished by four lighted pushbuttons, one i
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for each channel.
Trip marg'n (Q ) is variable batween 6 and 10 E
percent. O demands reset when within 6 percent of Q.
The light gp on each pushbutton indicates when the trlp limit must be reset if a
power level increase is scheduled.
The Q signal is limited so gp that, regardless of the logic describcd above, it cannot go above or j
below predetermined trip limits.
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Technical Specification 2.2.1, Limiting safety System Settings, Reactor Trip Sotpoints, requires that the high power trip setpoint be less than 10*. above thermal power, with a minimum setpoint of 30*4 of
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rated power and a maximum of less than 107?4 of rated thermal power, It also requires that the axial flux trip (which monitors a parameter
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r called "axial shape index" that is related to power distribution I
between the upper and lower parts of the core) setpoint be adjusted
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to within a tent shaped curve displaying acceptable axial shape index versus f raction of rated therr.ial power, i
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C.
D_e, tailed Description / Sequence of Events On vuly 4, 1988, Oper.tions personnel were starting up Unit 1 following a refueling outage.
The unit was beginning its first operating cycle utilizing a core designed for 24 months of operattsn.
Because of changes made in the core to support the 24 month cycle, fuel management (FM) personnel expected to see an approximate 30*4 r,ruuttion in the flux at the excore NI detectors when compared to pred ous cycles.
FM personnel had requested Systems Engineering to make an adjustment of NI power instrumentation to compensate for this reduction in such a manner that NI power would approximately match true power.
Due in part to the informal nature of the i
communications, that adjustment was never made. Therefore, operstors and FM personnel were not anticipating that this 30*4
- eductior. factor would be present at start up.
At 8:41
.m. on July 4, the 3,ain turbine gt. aerator was paralleled to the grid.
Indicated NI power was about 8*4.
Plsnt equipment performed as exp2cted for that power level, e.g. turbine bypass valve, shut as expected as load was applied " the turbine generator.
Power was escalated at 10:10 a.m. to 17*. by NI indication.
Differential emperature power indicated 22?4.
Power was to be hela
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at that level for about 3-1/2 hours to warm the turbine in preparation for a subsequent tv bine overspeed test.
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The reactee operator, although not clearly required to do so by
$rocedure, intended to do a nuclear instrument calibration in accordance with Operating Instructior. n! 30.
The requirement for
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performing an NI calibration is Note #15 in the control room log.
That note states "perform a ercore NI celibration as per 0130 daily at 8:00 p.m. (+/- 2 hiars) and any other time conditions make lt recessary when at mo:e than 15*4 of rated thermal power. AT power
I calibration potentiometer setting should be within the limits specified in the setpoint book".
OI 30 requires that a calorimetric first be performed to determine plant thermal power. 'Then NI power
is adjusted to correspond to the calorimetric power.
1 AT power is adjusted to match Ni power.
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The first step of the O! 3U procedure could not be completed because the computer point for calculating a calorimetric was not working. A
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.m n calorimetric calculation at that power level is difficult and ina a'. Mccuse it requires an hour of steauy state operation. At
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< el, i. e water control is in manual, varies considerably, d
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The control room operator
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(CRf, md N re-
'5e mismatch between NI power and AT power.
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i rii s s that NI power must be cecreased below 15's
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e test because,, design of the reactor
. actor will not receive a signal to trip when p re. t.
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reactor power is balow 15?4 However, he warted to use.n te 99 Q power (the hijher of NI or of power) to M fy being t, Therefore, he would either have to bring
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power down sufficiently to bring Q power below 15*; or be faced with
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trying to maintain NI power below 15'; with Q power meters possibly indicating above 15's.
Resolving the mismatch would simplify the problem.
At this point the CR0 improperly elected to deviate from 01 30 and carry out only the last two steps of OI 30, even though a calorimetric reference power was not available.
He asked permission from the shif t sepervisor to adjust AT power +o match NI powe r.
He chose this order of adjustment Decause it paralleled the sequence in O! 30.
He obtained permission to make the adjustment from the shift supervisor (SS).
In effect the CR0 was assuming NI power to be the
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correct power.
In fact, AT was the more correct power.
No attempt
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was made by the SS or CR0 to first consult with NF (technical
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support) personnel who were in the control roon prior to making the
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t.T adjustments.
Dif ferential temperature adjustments are made by means of a potentiometer on each RPS cabinet. A setpoint with an allowable adjustment band is provided for each potentiometer in the plant setpoint book.
The SS assumed the CR0 would only be making minor
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potentiometer changes which would not go beyond the allowable adjustment band.
The CR0 did not believe he was constrained to stay within the allowable setpoint band because he thought a note in the
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setpeint log released him from these limits.
T.,e noto did not exist i
at the time of the event in the Uni + 1 setpoint log.
However, the note did exist in the Unit 2 log.
The note.tated "deita T potentiometer settings are only valid at grester than 904 power, all
rods out and when RCS cold leg temperature is,tithin 1 degree F of its program value." About 10:30 a,m. the CR0 made large adjustments
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to the ai potentiometers in order to match power indications.
l Power was then reduced to 124 indicated, and the overspeed trip test j
was performed about 1:20 p.m.
The main generator was paralleled
back to the grid at 2:30 p.m.
About this time, NF personnel raalized that the plant computer calorimetric calculation (computer point PA 911) was not available.
They initiated a recuest for help in repairing the problem.
They
also noted that NI (nd AT power agreed and were indicating about 12*4 and that a plant computer generated ai power calculation (not the RPS erated AT power) was apparently high (indicating 16-17*,).
NF persocac1 were still not awsrc of the adjustment that had been made to AT power.
They were not cv acerned aboat the error between
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indicated poner and the computer AT power because the error was j
small.
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j Also about 2:39 p.m., the SS contacted the General Supervisor, Operations (G50) and informed hiin of the inoperable calorimetr ;c computer point.
The SS felt uneart about not having calorimetric
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information available.
It was agreed that power should be raised to i
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30*4 and a hand calerimetric performed.
This was discussed with and approved by NF personnel. The GS0's reasoning was that 30*4 was the first physics testing power plateau and had been selected for that purpose because it was, high enough in power to permit stable plant operation but low enough to provide relatively large margins to core parameter limits.
Thi:. 30?4 power plateau was over and hove start up testing requirements. The only place a calorimetric and NI calibration was required by formal procedure (other than the 8:00 p.m. daily check) was at the 85*4 start up test plateau.
l Power escalation *<as then begun.
NF personnel logged Nt power, AT power and the plant computer AT thermal power.
Unfortunately, the computer AT power reads out in MdT versus pe cent power, thus making it difficult to see developing mismatches.
Operators noted during the escalation tnat turbine generator output power appeared higher than expected for the indicated power level.
The 30*4 indicated power l
plateau vis reached about 6:00 p.m.
The computer calorimetric calculation point was repaired by 7:00 p.m. and tndicated 42'4 power.
NF personnel then verified it validity. Operatiens personnel completed the hand calorimetric about 8:33 p.m. and showed 44.29*4.
The 8:30 p.m. cor,tputer calorimetric showed 44.3'4 while NI and AT power were indicating 30*4.
The GSO was advised, and he directed that thtrmal power be reduced
l to 30's.
The AT potentiometer settings were found to have been significantly adjusted, e.g.,
had been moved from about 0.419 4.01
(setpoint) to 0.264.
The poten*.iometers were restored to utpoint l
and AT power then agreed with calorimetric power.
D.
Safety Cor erns snd Regulatory Issues The error in indicated power would ef *tetively cause the reactor
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j protection systen (RPS) to 4.llow the plant to reach a higher power
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level during a transient before initiating a rea tor trip.
Similarly, it created a potential for the RPS to allow a more severe
axial shape index before initiating a reactor trip.
However, it is
not clear that any limiting safety system settings were actually violated.
In the range of power in whit.h the plant was operating, the high power trip setpoint is required to be maintained less than 10*4 above indicated power.
Since indicated NI power would be prevented from increasing more than 10*4, in effect, thermal power increases would be proportionally limited.
If plant power had been allowed to approach full power with a large error still existing in indicated power, +. hen a situation would exist in which thermal power could have l
exceeded the maximum allowed trip setpoint.
This would be unlikely,
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since Nuclear Fuels personnel were planning to obtain a calorimetric at 30*4 power 'nd were required to record indicated power, plant computer AT and calorimetric power (computer point restored abcut
S:00 p.m.) after every 5*. increment in power.
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The associated procedure required power indications to be within 5%
of each other.
This should have flagged the problen before reaching higher power levels. With regard to the axial flux offset trip, normally RPS setpoints are typically set at values which are more conservative than the limits on the technical specification (TS)
curve. Therefore it is possible that even with the error in indicated power, trip setpoints may not have exceeded the TS limits.
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The licensee is determining whether any limiting safety system settings were exceeded and evaluating the impact of the potential relaxations in reactor trip setpoints on accident analyses.
The fact that operations personnel deviated from procedures and adjusted AT power (1) without suf t iciently questioning the
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i appropriateness of their planned ac. ions, (2) without first seeking
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advice from technical support personnel, and (3) without following proper protocol for a temporary procedure change is a concern.
The appropriateness of a note in the setpoint book associated with l
the AT setpoints is questionable.
The note s confusing. Operator
training in the area of allowable setpoint adjustments at lower powers may be weak.
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The formal start up test procedure (PSTP3) is weak in that it does i
not require a calorimetric and NI calibration until 85% power.
It does required logging of NI, AT power, and calor: metric power during power ascension, however, calorimetric power is in different units (MWT) than NI/ai power which makes it more difficult to see errors between power indications.
III Apparant Violations and General Weaknesses Highlighted by Both Events i
In summary, the failure to meet Technical Specti cation 3.8.1.1 with
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respect to the minimum number of AC puer sources demonstrated to be
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i operable is an apparent violatier. (50-318/88-17-01).
The failure to perform a calorimetric calculation per Operating Instruction 01 33 befort i
i making adjustments to nu: lear instrumentation and AT power is another apparent violation (50-318/88-17-02).
The issue of whether there was a violation of Technical Specification 2.2.1 rejarding Limiting Safety
System Settings, Reactor Trip Setpoints, remains unresolved until the licensee completes their evaluation and it is ruiewed further by NRC
(Unresolved Item 50-318/88-17-03).
a Both of the events discussed in this report reflect an underlying
wtakness.
This weakness points to a lack of questioning attitude and a willingness to pursue the selution to a given abnortnal situation without
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first obtaining required technical review and consistency with approved
procedures, i
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Similarly, on March 30, 1988, operators improperly allowed Unit 2 i
pressurizer / pressurizer spray line differential temperature to e a:d i
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fechnical Specification and procedural limits without verifying or sufficiently questioning whether such action had been properly reviewed
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and and approved (see detail 3 of Inspection Report 50-317/88-05, 318/88-06).
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In all of the aforementioned cases, operators took actions which deviated from procedures and made assumptions without (1) sufficiently questioning l
the appropriateness of their actions, (2) first seeking advice from
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technical support personnel, and (3) without following the existing
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procedures for processing a temporary procedure change.
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i A.
In the March 30 event, operators saw that the pressurizer / pressurizer l
spray line differential temperature was high and incorrectly assumed
that this was a preparatory condition for an expected engineering
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test and was therefore permissible.
B.
In the EDG voltage regulator event, the SS and CR0 incorrectly l
assumed that apparent deficiencies in the automatic voltage
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l regulator would not affect EDG operability and other operators J
assumed the EDG was operable with a voltage regulator in manual.
i C.
In the NI/aT power event, operators incorrectly assumed NI j
power indication was more accurate and adjusted AT power to match NI power,
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The lack of a sufficiently questioning attitude On the part of operations personnel appears to be a major cor.tributor to three significant events
and is a concern which must be addressed.
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I IV.
Exit Interview (30iO3)
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Meetings were periodically held with senior facility management to j
disc s the inspection scope and findings. A summary cf findings was
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press.ted to the licensee at the end of the inspection.
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