ML20245L574: Difference between revisions
StriderTol (talk | contribs) (StriderTol Bot change) |
StriderTol (talk | contribs) (StriderTol Bot change) |
||
Line 1: | Line 1: | ||
{{Adams | |||
| number = ML20245L574 | |||
| issue date = 07/26/1989 | |||
| title = Insp Repts 50-498/89-17 & 50-499/89-17 on 890601-30. Violations Noted.Major Areas Inspected:Plant Status,Licensee Action on Previous Insp Findings,Operational Safety Verification & Monthly Maint & Surveillance Observations | |||
| author name = Holler E | |||
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) | |||
| addressee name = | |||
| addressee affiliation = | |||
| docket = 05000498, 05000499 | |||
| license number = | |||
| contact person = | |||
| document report number = 50-498-89-17, 50-499-89-17, NUDOCS 8908220164 | |||
| package number = ML20245L549 | |||
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS | |||
| page count = 12 | |||
}} | |||
See also: [[see also::IR 05000498/1989017]] | |||
=Text= | |||
{{#Wiki_filter:_ | |||
. | |||
-.- | |||
. | |||
APPENDIX B | |||
U.S. NUCLEAR REGULATORY COMMISSION | |||
REGION IV | |||
NRC Inspection Report: 50-498/89-17 Operating Licenses: NPF-76 | |||
50-499/89-17' NPF-80 | |||
Dockets: 50-498 | |||
50-499 | |||
Licensee: Houston Lighting & Power Company (HL&P) | |||
P.O. Box 1700 | |||
Houston, Texas 77001 | |||
Facility Name: South Texas Project (STP), Units 1 and 2 | |||
Inspection At: STP, Matagorda County, Texas | |||
Inspection Conducted: June 1-30, 1989 | |||
Inspectors: J. E. Bess, Senior Resident Inspector, Unit 1 | |||
Project Section D, Division of Reactor | |||
Projects | |||
J. I. Tapia, Senior Resident Inspector | |||
Unit 2, Project Section D, Division of Reactor | |||
Projects | |||
R. J. Evans, Resident Inspector, Unit 1 | |||
Project Section D, Division of Reactor | |||
Projects | |||
D. L. Garrison, Resident Inspector, Unit 2 | |||
Project Section D, Division of Reactor | |||
Projects | |||
Approved: . A " | |||
d | |||
T. Jp Holler, Chief. Project Section D Date | |||
Division of Reactor Projects | |||
I | |||
Inspection Summary | |||
Inspection Conducted June 1-30, 1989 (Report 50-498/89-17; 50-499/89-17) | |||
Areas Inspected: Routine, unannounced inspection of plant status, licensee | |||
action on previous inspection findings, operational safety verification, i | |||
monthly maintenance observations, power ascension test, monthly surveillance | |||
observations, and startup test witnessing and observation, | |||
) | |||
f 8908220164 890915 | |||
' | |||
PDR ADOCK 05000498 | |||
Q PDC | |||
u_ | |||
- _____ . - - _ - _ | |||
, | |||
- | |||
. | |||
. . | |||
2 | |||
, | |||
Results: Within the areas ins | |||
fire watches (see paragraph 3)pected, | |||
. Weaknessesonewere | |||
violation noted was | |||
in theidentified licensee's regarding | |||
piping | |||
and. instrument diagrams (P& ids) of the Unit I standby diesel generator (DG) | |||
support. systems. The P& ids did not correctly reflect the as-built configuration | |||
of the support systems. Other Unit 1 DG support system weaknesses included | |||
identification tags missing from components, valves missing from the operating | |||
procedures and P& ids, and valve positions different between P&lD aad operating | |||
; procedures (see paragraph 5). Licensee strengths were that all Unit 1 DG | |||
support system valves and power supplies were in their correct position to | |||
support DG operation despite the procedure /P&lD weaknesses and the fact that | |||
the licensee had previously identified the deficiencies and implemented a | |||
program to correct them. Also, maintenance and surveillance activities were | |||
observed to be performed carefully and in accordance with procedures. Unit 2 | |||
successfully completed its startup testing program. | |||
_ _ _ _ - __ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ .. - | |||
_ _ - . | |||
, | |||
- | |||
. | |||
. | |||
. . | |||
3 | |||
DETAILS | |||
1. Persons Contacted | |||
*C. Ayala, Supervising Licensing Engineer | |||
*S. M. Dew, Manager, Nuclear Purchasing | |||
*A. C. McIntyre. Manager, Support Engineering | |||
*J. R. Lovell, Technical Service Manager | |||
*D. R. Keating, Quality Engineering Manager | |||
*J. W. Loesch, Plant Operations Manager , | |||
*V. A. Simons, Plant Opera-tions Support Manager | |||
*T. J. Jordan, Plant Engineering Manager | |||
*H. W. Dannbardt, Lead Operations Specialist | |||
*A. Khosla, Senior Licensing Engineer | |||
In addition to the above, the inspectors also held discussions with | |||
various licensee, architect engineer (AE), maintenance, and other | |||
contractor personnel during this inspection. | |||
* Denotes those individuals attending the exit interview cenducted on | |||
July 6, 1989. | |||
2. Plant Status | |||
Unit 1 began the inspection period at 100 percent reactor thermal power | |||
and remained at 100 percent until June 22, 1989. The reactor thermal | |||
power level was decreased to 90 percent for maintenance and surveillance | |||
testing of the turbine throttle and main steam isolation valves. The | |||
reactor. thermal power level was increased to 100 percent power on June 24, | |||
1989. The unit remained at 100 percent reactor thermal power through the | |||
end of the inspection period. | |||
Unit 2 began this inspection period at 75 percent reactor thermal power, , | |||
continuing with power ascension testing at that power plateau. On June 2 j | |||
1989, a Unit 2 reactor / generator trip occurred. This unplanned trip is j | |||
discussed in paragraph 3 of this report. On June 10, 1989, Unit 2 ; | |||
achieved 100 percent reactor thermal power. The 100-hour nuclear steam ; | |||
supply system (NSSS) acceptance test at that power level was successfully -) | |||
completed on June 16, 1989. Unit 2 was declared to be in commercial ' | |||
operation on June 19, 1989. At the end of this inspection period, Unit 2 ' | |||
remained at 100 percent reactor thermal power. | |||
3. Onsite Followup of Plant' Events (93702) | |||
l | |||
During the month of June, the boron concentration in Unit l's reactor | |||
coolant system was slowly decreased to maintain reactor power at | |||
100 percent. The unit is scheduled for a refueling outage to begin | |||
August 4, 1989. Several activities were performed during the inspection | |||
period to prepare the unit for the outage. A dummy fuel element with | |||
L __ -_ - - | |||
- | |||
. | |||
. . | |||
4 | |||
dimensions corresponding to a fuel element was used to verify the alignment | |||
of the cell walls for the new spent fuel racks'. The dummy fuel element | |||
was fully inserted and withdrawn from each fuel element storage cell in | |||
the new spent fuel racks to assure that irradiated fuel elements could be | |||
properly inserted into their designated storage positions. Also, the | |||
spent fuel pool was filled and boric acid was added to increase boron | |||
concentration to greater than 2500 ppm. | |||
On June 2, 1989, Unit 2 tripped while in Mode 1 at 76 percent power. | |||
Turbine inlet Throttle Valve TV-1 was closed during performance of the | |||
Main Turbine Steam inlet Valve Operability Test. The valve was opened in | |||
accordance with the procedure. The valve position was verified locally | |||
and on the main control board. The operator did not notice the " TURBINE | |||
STM STOP VLV RX PRETRIP" alarm, which actuated when the valve was closed | |||
and that the bistable indication did not clear. This indicated that the | |||
closed inlet valve input was still present at the solid state protection | |||
system (SSPS) reactor trip logic. The test procedure did not specify a | |||
check of this alarm or the bistable status after completing the valve | |||
cycle. | |||
Turbine inlet Throttle Valve TV-3 was closed per procedure. This | |||
completed the two of four turbine inlet throttle valve closed logic at the | |||
SSPS and generated a reactor turbine trip. The control rods inserted | |||
normally following the trip. No unexpected posttrip transients were | |||
noted. One steam generator power operated relief valve (PORV) was used to | |||
control RCS temperature and pressure. | |||
The licensee identified two causes of this event: (1) the test procedure | |||
did not require the operator to verify that the bistable had cleared | |||
following completion of the valve cycle, and (2) a defective limit switch | |||
on Valve TV-1 stuck in the valve-closed position after the valve was | |||
opened. The licensee replaced the defective switch and revised | |||
applicable test procedures. | |||
Each steam inlet throttle valve has a safety-related and a | |||
nonsafety-related limit switch that is activated in the closed position. | |||
The safety-related switch provides input to the reactor pretrip | |||
annunciator and the SSPS bistable. The nonsafety-related switch provides | |||
valve position indication on the main control board. When Valve TV-1 was | |||
opened, the safety-related limit switch remained in the valve-closed | |||
position and prevented the SSPS bistable from clearing. The | |||
nonsafety-related limit switch operated normally and gave the proper < | |||
indication of the valve position to the operator. | |||
On June 6,1989, the licensee provided the inspector with a station | |||
problem report regarding falsification of a fire watch log. The licensee | |||
had briefed the inspector regarding the incident and immediate corrective | |||
actions when the licensee first identified the issue in late April 1989. | |||
The station problem report, completed on May 31, 1989, provided details | |||
regarding the event and long-term corrective actions. | |||
. _ _ | |||
l | |||
. | |||
. | |||
. | |||
- - | |||
t | |||
5 | |||
Briefly, the event involved a contractor fire watchman who, after | |||
discovering thd another contractor fire watchman on duty at the same time | |||
l had apparently falsified an entry time on a fire watch log, reported the | |||
matter to the general foreman who, in turn, escalated the matter to the | |||
licensee's management. The licensee determined through an initial | |||
investigation on the same day the matter was reported that a false entry | |||
had been made and relieved the suspected fire watchman of duties. The | |||
suspected fire watchman was terminated a week later. The licensee's | |||
detailed investigation of the matter determined that the falsification had | |||
been limited to the terminated fire watchman. | |||
The safety significance of the missed fire watch round was relatively low. | |||
The watches were provided to monitor affected areas where a fire barrier | |||
was breached. The automatic fire detection and suppression systems were | |||
operable in the affected areas. Because of a previous event involving | |||
falsified fire watch log entries, the licensee had established procedures | |||
whereby three fire watchmen were assigned to make a specified round in | |||
succession. This was to ensure that an individual did not miss successive | |||
rounds in the same area. In this case, the time to detect a possible fire | |||
missed by the automatic fire detection system in the area where the | |||
terminated fire watchman falsified making his round was extended from 1 to | |||
2 hours. | |||
The licensee determined that dereliction of duty by the terminated fire | |||
watchman was the primary root cause. The licensee determined that the | |||
practice of leaving a blank space on the fire watch log to highlight a | |||
missed round was a contributing cause. Among its corrective actions, the | |||
licensee emphasized the consequences, including potential criminal | |||
prosecution, of falsifying documentation, stopped the practice of leaving | |||
a blank space to highlight a missed round, and emphasized the requirement | |||
to report a missed fire watch round to the shift supervisor or fire watch | |||
coordinator. | |||
Failure to perform fire watch rounds as required by licensee procedure is | |||
an apparent violation. HRC, by provision of its enforcement policy. | |||
10 CFR Part 2, Appendix C, Section V.G. 1, may refrain from issuing a | |||
notice of violation for violations of relatively low safety significance | |||
that are self-identified and corrected by a licensee. The provisions do | |||
not apply to willful violations. For this reason, this apparent violation | |||
will be cited (498/8917-01). The licensee's station problem report | |||
regarding the falsified fire watch log adequately discusses the event | |||
causes and corrective actions. | |||
On June 8, 1989, the Unit 1 No. 13 Standby Diesel Generator (DG) was | |||
started for testing in preparation for maintenance on a transformer. The | |||
DG immediately tripped. The licensee found that the "high temp main and | |||
conn rod brg or gen brg" alarm had actuated. This alarm had previously | |||
actuated on May 24, 1989, but the indication was not valid. The licensee | |||
could' not identify an actual problem that would have initiated either of | |||
these alarms. The licensee performed troubleshooting to determine the | |||
_ _ _ _ _ __ - _ _ _ - - _ _ _ _ _ - | |||
- - - | |||
' | |||
~ . | |||
, . | |||
6 | |||
cause of the DG trip. The licensee determined that the trips occurred | |||
'because.of a trip signal which is bypassed in the emergency mode. | |||
Inadequate air flow to' the shutdown air header prevented the pneumatic | |||
trip switch from resetting before the electric trips were unblocked. The | |||
licensee replaced the air filter, Jir regulating valve, and the pressure | |||
switch in the--shutdown air header, and tested the DG successfully. These | |||
events were classified as nonvalid failures in accordance with criteria | |||
in Regulatory Guide 1.108. The test interval.for No.13 DG remained ac | |||
31 days. The licensee determined that the DG would have performed the | |||
required safety functions without tripping, should any have occurred. | |||
There have been no valid failures of the No. 13 DG. | |||
The primary meteorological tower was declared out of service on June 19, | |||
1989, and was returned to service on June 29, 1989. Since the tower was | |||
out of service more than 7 days, a special report regarding an inoperable | |||
primary meteorological tower was required to be submitted to the NRC | |||
(report was submitted July 6, 1989). | |||
4. Licensee Action on Previous Inspection Findings (92701) | |||
(Closed) Open Item (498/8902-01): Essential Chiller Temperature Control | |||
Switch - In NRC Inspection Report 50-498/89-02; 50-499/89-02, the Unit 1 | |||
essential chilled water system was inspected. A temperature control point | |||
switch was identified in the local chiller panels, but this switch was not | |||
discussed in the operating procedure. | |||
Since the inspection, Procedure 1 POP 02-CH-0001, " Essential Chilled Water | |||
System," was revised to Revision 6. The updated procedure contained | |||
Step 8.1.5 that instructed operations department personnel to adjust the | |||
temperature control switch to the operating temperature range. | |||
5. Operational Safety Verification (71707) | |||
Operation safety verification inspections were performed to ensure the | |||
facility was being operated safely and in conformance with licensee and | |||
regulatory requirements. Items inspected on a routine basis included: | |||
control room staffing, control room logbooks, plant housekeeping, plant | |||
security, health physics, system and control board lineups, and general | |||
plant / equipment conditions. | |||
. Itsms noted and reported to the ' licensee during plant tours included: | |||
* | |||
The cable guards on two flexible conduit were noted to be pulled | |||
loose from endpoint connections. The loose conduit (AIXG1CRX003 and | |||
N1DGBDXC0051) required rework to protect the cables inside the | |||
conduit. Both were located in DG Room 11. | |||
A seal (yellow ty-rap) was noted not to be sealing on an " Emergency | |||
Use Only" storage box. The licensee replaced all seals with metal | |||
1ocks. | |||
L _ . - - - - - - . ---- _ _ _ o | |||
. | |||
.. | |||
~ | |||
W ' | |||
,: ', .' ; | |||
7 | |||
. | |||
.. | |||
. | |||
Two drain valves (1-PD-0378 and.1-PD-0379) were required to be locked | |||
shut per the locked valve program. The valves were locked shut in | |||
_m the interest of good engineering practice and not for. reasons of | |||
reactor safety. The locking devices were noted to be improperly | |||
attached to the valves. This condition was reported to the Unit 1 | |||
i | |||
control room. ;0perations removed the cables and seals, then tagged | |||
the valves in the shut position using the tag out procedure. | |||
* | |||
Inspections;of housekeeping were performed on a routine basis, | |||
including.the Unit.1 mechanical auxiliary building (MAB). In the | |||
MAB,' the floor of Room 327, 54-foot elevation, was noted to be | |||
unusually dirty. - Trash, nails, bits of wood and sawdust, and other | |||
. | |||
: items were noted throughout the room, which was used as temporary | |||
storage. The room has since been cleaned.- | |||
' | |||
'As part of the operational safety verification portion of the inspection, | |||
the standby DG No.-11 support systems were inspected. The support systems | |||
were compared to the electrical, valve, and instrument lineups | |||
. (Procedure IPOP02-DG-0001. " Emergency Diesel Generator No.11," | |||
Revision 6) and Loth the Bechtel and vendor (Cooper Energy Services) | |||
supplied P& ids. The diesel generator support systems inspected included: | |||
- | |||
Fuel Oil Storage and Transfer System (system designator F0) | |||
* | |||
Lube Oil System (LO) | |||
* | |||
Jacket Water. System (JW) | |||
Cooling Water System (DG) | |||
Starting Air System (SD) | |||
Air Intake and Exhaust System (DI) | |||
Observations made during the system walkdowns included: | |||
* | |||
Ten valves and one pressure indicator were missing identification | |||
tags. | |||
One nonsafety-related temperature indicator (DG No.12 L0 | |||
temperature) was reading 4*F less than the minimum value allowed by | |||
Procedure IPOP02-DG-0002, Step 5.23. This was reported to the shift i | |||
supervisor who initiated corrective actions. | |||
* Local Level Indicator LI-9109A (fuel oil storage tank level) was | |||
missingitsengineeringunits(%). The indicator was located on | |||
local Control Panel ZLP102. | |||
* | |||
Twodifferentvalveshadthesameidentificationnumber(1-LU-3012). ; | |||
* The wrong cubicle was listed as power supply for Distribution | |||
Panel DPA135 in the electrical lineup and on the local panel ! | |||
nameplate (the lineup was corrected in Revision 7 of d | |||
l | |||
Procedure IP0P02-DG-0001, which was approved June 27,1989). | |||
_o | |||
- -- | |||
I J | |||
* . | |||
8 | |||
* | |||
Five valves shown on the P& ids were not listed in Revision 6 of the | |||
procedure lineup. One valve was subsequently added to the lineup by | |||
Revision 7 to the procedure, two valves apparently did not exist, and | |||
two valves (nonsafety-related vent valves) were added to the | |||
procedure by recent field change requests (FCRs). | |||
" | |||
Five valves were found to be in different positions in the valve | |||
lineup than the position shown on the P&lDs. The P& ids were | |||
apparently incorrect in all five cases. One valve, 1-JW-0031, was | |||
shown locked shut on one drawing and open on another. | |||
Valve 1-JW-0031 was in the correct position for system operation. | |||
* | |||
Several valves were found that were not shown on any P&ID, not | |||
labelled, or not listed in the valve lineups. The valves included | |||
several safety-related instrument root' valves, one L0 filter drain | |||
valve, and two L0 strainer drain valves. | |||
Walkdowns of the support systems were performed using both vendor and | |||
Bechtel P& ids. For the SD and F0 systems, the Bechtel P&ID showed only | |||
the Bechtel supplied items in detail, while the vendor P&ID showed only | |||
vendor supplied items in detail. All SD and F0 P& ids were noted to have | |||
minor errors, including missing valves and wrong valve positions. For the | |||
JW, LO, and DG systems, Bechtel P& ids were drawn from vendor P& ids. | |||
Numerous errors in the vendor P& ids were simply carried over onto the | |||
Bechtel drawings. In the JW P& ids, the basic flowpaths were correct, but | |||
many components were 'shown in the wrong locations. Instrumentation root j | |||
valves were not shown on the JW P& ids. In the DG P& ids, the flowpaths for | |||
the intercoolers and fuel oil coolers, a major portion of the vendor and | |||
Bechtel P& ids, were incorrectly drawn. The L0 P& ids drawn by Bechtel | |||
contained the most errors. Flowpaths were incorrectly drawn, valve | |||
numbers were incorrect for about 20 valves, equipment was shown in the | |||
wrong location, and at least one root valve was missing. | |||
All valves and power supplies were noted to be in the correct position | |||
needed to support DG No.11 operation. The details of the inspection were | |||
presented to the licensee for corrective actions. The licensee was aware | |||
of the problem with the diesel generator support systems P& ids. In | |||
January 1988, plant engineering sent support engineering an engineering ]; | |||
support request, which identified the problem. In April 1989, support | |||
- engineering generated an action item, which was a plan of action. At the | |||
end of the inspection period, the action item was still in the review | |||
process and system walkdowns were still in progress. The inspectors | |||
discussed with the licensee a concern that corrective actions needed to | |||
correct the drawing errors were not prompt. The licensee stated that . | |||
manpower resources were being used to upgrade the vendor manuals, l | |||
illegible vendor drawings, and design basis documents, which had | |||
priorities over the P& ids. The licensee also stated that the work to | |||
upgrade the P& ids would be completed by the end of the year. The work | |||
scope would include completion of walkdowns, revision of drawings, and | |||
tagging vendor supplied equipment. j | |||
1 | |||
I | |||
_ _ _ - - - _ ) | |||
_ _ _ _ _ | |||
- | |||
: ; | |||
9 | |||
No violations or deviations were identified in this area of the | |||
inspection. | |||
6. Monthly Maintenance Observation (62703) | |||
Selected maintenance activities were observed to ascertain whether the | |||
activities were conducted in accordance with approved procedures. The | |||
activities included: | |||
* | |||
OPMP08-SI-0904, Revision 0, "HHSI Pump A Discharge Pressure | |||
4 | |||
Calibration (P-0904)" | |||
* | |||
PreventiveMaintenance(PM)IC-1-SI-86003948 Revision 2.C, "HHSI | |||
Pump A Discharge Calibration" | |||
* | |||
PM MM-1-HF-89000869, Revision 0.B. " Fuel Handling Building Exhaust | |||
Fan 11C Discharge Damper' Lube / Inspection" | |||
The' inspectors determined through observations and procedure reviews | |||
that approved procedures were being used, replacement parts were | |||
properly certified. the equipment was properly returned to service, and | |||
. | |||
housekeeping was being maintained. The inspectors also determined that | |||
the technicians were familiar and knowledgeable of the work process and | |||
the documentation was adequate to cover the process. | |||
No violations or deviations were identified in this area of the | |||
inspection. | |||
7. Monthly Surveillance Observations (61726) | |||
Selected surveillance activities were observed to ascertain whether the | |||
surveillance of safety significant systems and components were being | |||
conducted in accordance with Technical Specifications (TS) and other | |||
requirements. The following surveillance tests were observed and | |||
reviewed: | |||
1 PSP 06-PK-0004, Revision 5, "4.16KV Class 1E Undervoltage Relay | |||
Channel Calibration /TADOT-Channel 4," performed on 4.16KV Bus EIA | |||
* 2 PSP 06-DJ0001, Revision 1, "125 Volt Class lE Battery 7 Day | |||
Surveillance Test," performed on Battery E2C11 | |||
The inspectors verified that testing was performed using approved | |||
procedures, final test data was within acceptance criteria limits, | |||
housekeeping was maintained by the technicians, and test equipment was | |||
within required calibration cycles. A technical review of the procedures | |||
, | |||
was also performed, with no concerns being identified. | |||
' | |||
No violations or deviations were identified in this area of the | |||
inspection. | |||
, | |||
___--__x.____ _ __ _ _ _ _ _ . - - _ _ _ _ _ . | |||
_ _ _ _ _ _ _ | |||
a , | |||
% , ., _ ~ | |||
m . . . , | |||
, | |||
10 ] | |||
^ | |||
8. Startup Test Witnessing and Observation (72302) | |||
Selected Unit 2 startup tests were witnessed to ascertain conformance by | |||
the licensee to procedural requirements, observe staff performance, and | |||
. ascertain the adequacy of test program records. The tests that were | |||
observed included: | |||
* 2 PEP 04-ZG0002, Revision 0, " Loose Parts Monitoring System Baseline | |||
Data" | |||
* | |||
2 PEPO 4-ZY-0070, Revision 1 " Test Sequence at 75% Power" | |||
* | |||
2 PEP 04-ZY-0072, Revision 0, "Incore-Excore Detector Calibration" | |||
The inspectors monitored portions of the performance of the vibration and | |||
loose parts monitoring system at the 90 percent reactor thermal power | |||
level utilizing Procedure 2 PEPO 4-ZG-0002. The baseline data procedure | |||
required data to be recorded for a minimum of 10 minutes at the 30-; 50 , | |||
75 , and 100 percent power plateaus, however, other plateaus were | |||
included. The data were then used to produce power spectral density | |||
signatures at center frequencies of 25 , 250 , 2500 , and 25,000Hz. The | |||
procedure and signoffs were reviewed during and after the testing, as was | |||
the calibration and setup of the equipment. | |||
The data sheets and plots of each channel and frequency were reviewed and | |||
found to'contain the required data. It was noted that two sensors had | |||
become uncoupled from the reactor vessel and had been addressed in Problem | |||
Report 89-113. | |||
The inspectors continued the inspection of progressive testing of | |||
equipment at various power levels in order to verify that the licensee was | |||
correctly implementing the power ascension testing program. | |||
The incore/excore cross calibration was performed at 75 percent reactor | |||
power as specified in Procedure 2 PEP 04-ZY-0070 and as detailed in | |||
Procedure 2 PEP 04-2Y-0072 and Field Change Request (FCR) 89-1510. The | |||
purpose of the test was to determine the relationship between incore and | |||
~ | |||
excore axial offset, provide data for calibration of the excore axial flux | |||
difference (AFD) amplifiers,andprovidedatatocalibratetheflux | |||
(Delta = I) penalty to the over temperature, delta temperature protective | |||
setpoints. The test method was as follows: | |||
'*' Obtain a full core flux and thermocouple map with rods out. | |||
Dilute Control Bank D inward and obtain quarter core flux map and | |||
thermocouple map at each 2 percent decrease in AFD. | |||
* Obtain full core flux and thermocouple map at 90 percent of axial | |||
offset negative limit. | |||
. - - _ - _ - - - - __ __ ___-_____ - __ _ _ _ _ _ _ | |||
_ -__ | |||
t | |||
, . | |||
, | |||
. | |||
I | |||
11 | |||
* | |||
Borate Control Bank D outward and obtain quarter core flux map and | |||
thermocouple map at each 2 percent increase in AFD. | |||
Obtain a full core flux and thermocouple map with AFD at its most | |||
positive value. | |||
On completion of the mapping, the data was reduced by computer to yield | |||
incore/excore detector calibration values. | |||
The inspectors witnessed the test preparation and the data acquisition. | |||
The flux mapping used the standard Westinghouse data collection system with | |||
the six channels recording simultaneously. Each flux det3ctor was fully | |||
inserted and withdrawn. The detectors mapped the full leagth of the core | |||
for each insertion. Each chart was stamped and identified and the data | |||
sheets completed. All data were entered into the plant Proteus Ccmputer | |||
from which further calculations were made for final data reduction and | |||
comparison with test data. | |||
On completion of the test and acquisition, the inspector reviewed the test | |||
procedure for completeness through the step in the procedure that ended | |||
the data collection (Step 6.30). The generated chart data were found to | |||
be adequate in content and reflected the correct flux patterns that were | |||
expected. | |||
No violations or deviations were identified in this area of the | |||
inspection. | |||
9. Power Ascension Test - Plant Trip From 100% Power (72580) | |||
The licensee performed a full load rejection test to demonstrate the | |||
ability of Unit 2 to sustain a trip of the main generator from 100 percent | |||
reactor thermal power. The test was performed using | |||
Procedure 2 PEP 04-ZY-0102, " Plant Trip from 100% Power," Revision 0. The | |||
inspectors witnessed performance of the procedure by the licensee. The | |||
procedure provided instructions to record initial data prior to the plant | |||
trip, to trip the plant, to record post trip data, and to perform a | |||
posttrip review. | |||
l | |||
Pertinent plant parameters were recorded to determine control system | |||
response to the transient. A review of the posttrip data revealed all | |||
acceptance criteria were met. However, two test criteria were not met: | |||
the maximum pressurizer pressure recorded was higher than the initial | |||
value by 41 psig (pressurizer pressure was expected to drop below the | |||
initial value of 2235 psig), and the steam generator level for each loop | |||
failed to drop out of the narrow range band. Subsequent evaluation and | |||
feedback from Westinghouse disclosed that these two criteria had no impact | |||
on the overall acceptability of the test. i | |||
_ _ _ _ _ _ _ _ _ _ _ _ - _ _ | |||
, | |||
, | |||
j. . | |||
. | |||
.. | |||
3 ~ ;- | |||
12 | |||
- | |||
_ | |||
X, . | |||
Other observations made during the test included: the reactor coolant | |||
system (RCS) cooled down to SEB*F. 9'F-lower than the no-load value of | |||
" | |||
567'F, because of the slow. closure time of the moisture separator reheater | |||
~ .temocrature control volves; an auxiliary feedwater regulating valve | |||
,s ... indicated partially open while fully closed; and the digital rod position | |||
* | |||
' indication (DRPI) gave an erroneous flashing. general warning light for a | |||
control' rod.that was full in.following the reactor trip. The licensee and | |||
' | |||
c . Westinghouse reviewed and analyzed the cooldown from 567"F to 558"F. The | |||
' | |||
cooldown was greater.than anticipated, but within the acceptance limits | |||
for the test. | |||
The effect of the Unit 2 trip'was noticed in the Unit 1' control room. A | |||
variation in electrical grid frequency was recorded. Frequency dropped | |||
:from 60 to 59.7Hz, then returned to 60Hz. Several alarms were | |||
momentarily received in the Unit I control room, including inverter | |||
trouble, annunciator ground detected, and plant computer inverter failure | |||
alarms. | |||
A review of Procedure 2 PEP 04-ZY-0102 was performed. The procedure was | |||
compared to licensee commitments, including Final Safety Analysis | |||
Report Section 14.2.12.3.23, " Full Load Rejection Test." | |||
No violations or deviations were identified in this area of the | |||
inspection. | |||
10. Exit Interview | |||
The inspectors met with licensee representatives (denoted in paragraph 1) | |||
on July 6, 1989. The inspectors summarized the scope and findings of the | |||
inspection. The' licensee did not identify, as proprietary, any of the | |||
information provided to, or reviewed by, the inspectors. | |||
L. | |||
_ _ _ _ - - _ - _ _ _ _ _ . | |||
}} |
Latest revision as of 23:55, 31 January 2022
ML20245L574 | |
Person / Time | |
---|---|
Site: | South Texas |
Issue date: | 07/26/1989 |
From: | Holler E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
To: | |
Shared Package | |
ML20245L549 | List: |
References | |
50-498-89-17, 50-499-89-17, NUDOCS 8908220164 | |
Download: ML20245L574 (12) | |
See also: IR 05000498/1989017
Text
_
.
-.-
.
APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report: 50-498/89-17 Operating Licenses: NPF-76
50-499/89-17' NPF-80
Dockets: 50-498
50-499
Licensee: Houston Lighting & Power Company (HL&P)
P.O. Box 1700
Houston, Texas 77001
Facility Name: South Texas Project (STP), Units 1 and 2
Inspection At: STP, Matagorda County, Texas
Inspection Conducted: June 1-30, 1989
Inspectors: J. E. Bess, Senior Resident Inspector, Unit 1
Project Section D, Division of Reactor
Projects
J. I. Tapia, Senior Resident Inspector
Unit 2, Project Section D, Division of Reactor
Projects
R. J. Evans, Resident Inspector, Unit 1
Project Section D, Division of Reactor
Projects
D. L. Garrison, Resident Inspector, Unit 2
Project Section D, Division of Reactor
Projects
Approved: . A "
d
T. Jp Holler, Chief. Project Section D Date
Division of Reactor Projects
I
Inspection Summary
Inspection Conducted June 1-30, 1989 (Report 50-498/89-17; 50-499/89-17)
Areas Inspected: Routine, unannounced inspection of plant status, licensee
action on previous inspection findings, operational safety verification, i
monthly maintenance observations, power ascension test, monthly surveillance
observations, and startup test witnessing and observation,
)
f 8908220164 890915
'
PDR ADOCK 05000498
Q PDC
u_
- _____ . - - _ - _
,
-
.
. .
2
,
Results: Within the areas ins
fire watches (see paragraph 3)pected,
. Weaknessesonewere
violation noted was
in theidentified licensee's regarding
piping
and. instrument diagrams (P& ids) of the Unit I standby diesel generator (DG)
support. systems. The P& ids did not correctly reflect the as-built configuration
of the support systems. Other Unit 1 DG support system weaknesses included
identification tags missing from components, valves missing from the operating
procedures and P& ids, and valve positions different between P&lD aad operating
- procedures (see paragraph 5). Licensee strengths were that all Unit 1 DG
support system valves and power supplies were in their correct position to
support DG operation despite the procedure /P&lD weaknesses and the fact that
the licensee had previously identified the deficiencies and implemented a
program to correct them. Also, maintenance and surveillance activities were
observed to be performed carefully and in accordance with procedures. Unit 2
successfully completed its startup testing program.
_ _ _ _ - __ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ .. -
_ _ - .
,
-
.
.
. .
3
DETAILS
1. Persons Contacted
- C. Ayala, Supervising Licensing Engineer
- S. M. Dew, Manager, Nuclear Purchasing
- A. C. McIntyre. Manager, Support Engineering
- J. R. Lovell, Technical Service Manager
- D. R. Keating, Quality Engineering Manager
- J. W. Loesch, Plant Operations Manager ,
- V. A. Simons, Plant Opera-tions Support Manager
- T. J. Jordan, Plant Engineering Manager
- H. W. Dannbardt, Lead Operations Specialist
- A. Khosla, Senior Licensing Engineer
In addition to the above, the inspectors also held discussions with
various licensee, architect engineer (AE), maintenance, and other
contractor personnel during this inspection.
- Denotes those individuals attending the exit interview cenducted on
July 6, 1989.
2. Plant Status
Unit 1 began the inspection period at 100 percent reactor thermal power
and remained at 100 percent until June 22, 1989. The reactor thermal
power level was decreased to 90 percent for maintenance and surveillance
testing of the turbine throttle and main steam isolation valves. The
reactor. thermal power level was increased to 100 percent power on June 24,
1989. The unit remained at 100 percent reactor thermal power through the
end of the inspection period.
Unit 2 began this inspection period at 75 percent reactor thermal power, ,
continuing with power ascension testing at that power plateau. On June 2 j
1989, a Unit 2 reactor / generator trip occurred. This unplanned trip is j
discussed in paragraph 3 of this report. On June 10, 1989, Unit 2 ;
achieved 100 percent reactor thermal power. The 100-hour nuclear steam ;
supply system (NSSS) acceptance test at that power level was successfully -)
completed on June 16, 1989. Unit 2 was declared to be in commercial '
operation on June 19, 1989. At the end of this inspection period, Unit 2 '
remained at 100 percent reactor thermal power.
3. Onsite Followup of Plant' Events (93702)
l
During the month of June, the boron concentration in Unit l's reactor
coolant system was slowly decreased to maintain reactor power at
100 percent. The unit is scheduled for a refueling outage to begin
August 4, 1989. Several activities were performed during the inspection
period to prepare the unit for the outage. A dummy fuel element with
L __ -_ - -
-
.
. .
4
dimensions corresponding to a fuel element was used to verify the alignment
of the cell walls for the new spent fuel racks'. The dummy fuel element
was fully inserted and withdrawn from each fuel element storage cell in
the new spent fuel racks to assure that irradiated fuel elements could be
properly inserted into their designated storage positions. Also, the
spent fuel pool was filled and boric acid was added to increase boron
concentration to greater than 2500 ppm.
On June 2, 1989, Unit 2 tripped while in Mode 1 at 76 percent power.
Turbine inlet Throttle Valve TV-1 was closed during performance of the
Main Turbine Steam inlet Valve Operability Test. The valve was opened in
accordance with the procedure. The valve position was verified locally
and on the main control board. The operator did not notice the " TURBINE
STM STOP VLV RX PRETRIP" alarm, which actuated when the valve was closed
and that the bistable indication did not clear. This indicated that the
closed inlet valve input was still present at the solid state protection
system (SSPS) reactor trip logic. The test procedure did not specify a
check of this alarm or the bistable status after completing the valve
cycle.
Turbine inlet Throttle Valve TV-3 was closed per procedure. This
completed the two of four turbine inlet throttle valve closed logic at the
SSPS and generated a reactor turbine trip. The control rods inserted
normally following the trip. No unexpected posttrip transients were
noted. One steam generator power operated relief valve (PORV) was used to
control RCS temperature and pressure.
The licensee identified two causes of this event: (1) the test procedure
did not require the operator to verify that the bistable had cleared
following completion of the valve cycle, and (2) a defective limit switch
on Valve TV-1 stuck in the valve-closed position after the valve was
opened. The licensee replaced the defective switch and revised
applicable test procedures.
Each steam inlet throttle valve has a safety-related and a
nonsafety-related limit switch that is activated in the closed position.
The safety-related switch provides input to the reactor pretrip
annunciator and the SSPS bistable. The nonsafety-related switch provides
valve position indication on the main control board. When Valve TV-1 was
opened, the safety-related limit switch remained in the valve-closed
position and prevented the SSPS bistable from clearing. The
nonsafety-related limit switch operated normally and gave the proper <
indication of the valve position to the operator.
On June 6,1989, the licensee provided the inspector with a station
problem report regarding falsification of a fire watch log. The licensee
had briefed the inspector regarding the incident and immediate corrective
actions when the licensee first identified the issue in late April 1989.
The station problem report, completed on May 31, 1989, provided details
regarding the event and long-term corrective actions.
. _ _
l
.
.
.
- -
t
5
Briefly, the event involved a contractor fire watchman who, after
discovering thd another contractor fire watchman on duty at the same time
l had apparently falsified an entry time on a fire watch log, reported the
matter to the general foreman who, in turn, escalated the matter to the
licensee's management. The licensee determined through an initial
investigation on the same day the matter was reported that a false entry
had been made and relieved the suspected fire watchman of duties. The
suspected fire watchman was terminated a week later. The licensee's
detailed investigation of the matter determined that the falsification had
been limited to the terminated fire watchman.
The safety significance of the missed fire watch round was relatively low.
The watches were provided to monitor affected areas where a fire barrier
was breached. The automatic fire detection and suppression systems were
operable in the affected areas. Because of a previous event involving
falsified fire watch log entries, the licensee had established procedures
whereby three fire watchmen were assigned to make a specified round in
succession. This was to ensure that an individual did not miss successive
rounds in the same area. In this case, the time to detect a possible fire
missed by the automatic fire detection system in the area where the
terminated fire watchman falsified making his round was extended from 1 to
2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The licensee determined that dereliction of duty by the terminated fire
watchman was the primary root cause. The licensee determined that the
practice of leaving a blank space on the fire watch log to highlight a
missed round was a contributing cause. Among its corrective actions, the
licensee emphasized the consequences, including potential criminal
prosecution, of falsifying documentation, stopped the practice of leaving
a blank space to highlight a missed round, and emphasized the requirement
to report a missed fire watch round to the shift supervisor or fire watch
coordinator.
Failure to perform fire watch rounds as required by licensee procedure is
an apparent violation. HRC, by provision of its enforcement policy.
10 CFR Part 2, Appendix C, Section V.G. 1, may refrain from issuing a
notice of violation for violations of relatively low safety significance
that are self-identified and corrected by a licensee. The provisions do
not apply to willful violations. For this reason, this apparent violation
will be cited (498/8917-01). The licensee's station problem report
regarding the falsified fire watch log adequately discusses the event
causes and corrective actions.
On June 8, 1989, the Unit 1 No. 13 Standby Diesel Generator (DG) was
started for testing in preparation for maintenance on a transformer. The
DG immediately tripped. The licensee found that the "high temp main and
conn rod brg or gen brg" alarm had actuated. This alarm had previously
actuated on May 24, 1989, but the indication was not valid. The licensee
could' not identify an actual problem that would have initiated either of
these alarms. The licensee performed troubleshooting to determine the
_ _ _ _ _ __ - _ _ _ - - _ _ _ _ _ -
- - -
'
~ .
, .
6
cause of the DG trip. The licensee determined that the trips occurred
'because.of a trip signal which is bypassed in the emergency mode.
Inadequate air flow to' the shutdown air header prevented the pneumatic
trip switch from resetting before the electric trips were unblocked. The
licensee replaced the air filter, Jir regulating valve, and the pressure
switch in the--shutdown air header, and tested the DG successfully. These
events were classified as nonvalid failures in accordance with criteria
in Regulatory Guide 1.108. The test interval.for No.13 DG remained ac
31 days. The licensee determined that the DG would have performed the
required safety functions without tripping, should any have occurred.
There have been no valid failures of the No. 13 DG.
The primary meteorological tower was declared out of service on June 19,
1989, and was returned to service on June 29, 1989. Since the tower was
out of service more than 7 days, a special report regarding an inoperable
primary meteorological tower was required to be submitted to the NRC
(report was submitted July 6, 1989).
4. Licensee Action on Previous Inspection Findings (92701)
(Closed) Open Item (498/8902-01): Essential Chiller Temperature Control
Switch - In NRC Inspection Report 50-498/89-02; 50-499/89-02, the Unit 1
essential chilled water system was inspected. A temperature control point
switch was identified in the local chiller panels, but this switch was not
discussed in the operating procedure.
Since the inspection, Procedure 1 POP 02-CH-0001, " Essential Chilled Water
System," was revised to Revision 6. The updated procedure contained
Step 8.1.5 that instructed operations department personnel to adjust the
temperature control switch to the operating temperature range.
5. Operational Safety Verification (71707)
Operation safety verification inspections were performed to ensure the
facility was being operated safely and in conformance with licensee and
regulatory requirements. Items inspected on a routine basis included:
control room staffing, control room logbooks, plant housekeeping, plant
security, health physics, system and control board lineups, and general
plant / equipment conditions.
. Itsms noted and reported to the ' licensee during plant tours included:
The cable guards on two flexible conduit were noted to be pulled
loose from endpoint connections. The loose conduit (AIXG1CRX003 and
N1DGBDXC0051) required rework to protect the cables inside the
conduit. Both were located in DG Room 11.
A seal (yellow ty-rap) was noted not to be sealing on an " Emergency
Use Only" storage box. The licensee replaced all seals with metal
1ocks.
L _ . - - - - - - . ---- _ _ _ o
.
..
~
W '
,: ', .' ;
7
.
..
.
Two drain valves (1-PD-0378 and.1-PD-0379) were required to be locked
shut per the locked valve program. The valves were locked shut in
_m the interest of good engineering practice and not for. reasons of
reactor safety. The locking devices were noted to be improperly
attached to the valves. This condition was reported to the Unit 1
i
control room. ;0perations removed the cables and seals, then tagged
the valves in the shut position using the tag out procedure.
Inspections;of housekeeping were performed on a routine basis,
including.the Unit.1 mechanical auxiliary building (MAB). In the
MAB,' the floor of Room 327, 54-foot elevation, was noted to be
unusually dirty. - Trash, nails, bits of wood and sawdust, and other
.
- items were noted throughout the room, which was used as temporary
storage. The room has since been cleaned.-
'
'As part of the operational safety verification portion of the inspection,
the standby DG No.-11 support systems were inspected. The support systems
were compared to the electrical, valve, and instrument lineups
. (Procedure IPOP02-DG-0001. " Emergency Diesel Generator No.11,"
Revision 6) and Loth the Bechtel and vendor (Cooper Energy Services)
supplied P& ids. The diesel generator support systems inspected included:
-
Fuel Oil Storage and Transfer System (system designator F0)
Jacket Water. System (JW)
Cooling Water System (DG)
Starting Air System (SD)
Air Intake and Exhaust System (DI)
Observations made during the system walkdowns included:
Ten valves and one pressure indicator were missing identification
tags.
One nonsafety-related temperature indicator (DG No.12 L0
temperature) was reading 4*F less than the minimum value allowed by
Procedure IPOP02-DG-0002, Step 5.23. This was reported to the shift i
supervisor who initiated corrective actions.
- Local Level Indicator LI-9109A (fuel oil storage tank level) was
missingitsengineeringunits(%). The indicator was located on
local Control Panel ZLP102.
Twodifferentvalveshadthesameidentificationnumber(1-LU-3012). ;
- The wrong cubicle was listed as power supply for Distribution
Panel DPA135 in the electrical lineup and on the local panel !
nameplate (the lineup was corrected in Revision 7 of d
l
Procedure IP0P02-DG-0001, which was approved June 27,1989).
_o
- --
I J
- .
8
Five valves shown on the P& ids were not listed in Revision 6 of the
procedure lineup. One valve was subsequently added to the lineup by
Revision 7 to the procedure, two valves apparently did not exist, and
two valves (nonsafety-related vent valves) were added to the
procedure by recent field change requests (FCRs).
"
Five valves were found to be in different positions in the valve
lineup than the position shown on the P&lDs. The P& ids were
apparently incorrect in all five cases. One valve, 1-JW-0031, was
shown locked shut on one drawing and open on another.
Valve 1-JW-0031 was in the correct position for system operation.
Several valves were found that were not shown on any P&ID, not
labelled, or not listed in the valve lineups. The valves included
several safety-related instrument root' valves, one L0 filter drain
valve, and two L0 strainer drain valves.
Walkdowns of the support systems were performed using both vendor and
Bechtel P& ids. For the SD and F0 systems, the Bechtel P&ID showed only
the Bechtel supplied items in detail, while the vendor P&ID showed only
vendor supplied items in detail. All SD and F0 P& ids were noted to have
minor errors, including missing valves and wrong valve positions. For the
JW, LO, and DG systems, Bechtel P& ids were drawn from vendor P& ids.
Numerous errors in the vendor P& ids were simply carried over onto the
Bechtel drawings. In the JW P& ids, the basic flowpaths were correct, but
many components were 'shown in the wrong locations. Instrumentation root j
valves were not shown on the JW P& ids. In the DG P& ids, the flowpaths for
the intercoolers and fuel oil coolers, a major portion of the vendor and
Bechtel P& ids, were incorrectly drawn. The L0 P& ids drawn by Bechtel
contained the most errors. Flowpaths were incorrectly drawn, valve
numbers were incorrect for about 20 valves, equipment was shown in the
wrong location, and at least one root valve was missing.
All valves and power supplies were noted to be in the correct position
needed to support DG No.11 operation. The details of the inspection were
presented to the licensee for corrective actions. The licensee was aware
of the problem with the diesel generator support systems P& ids. In
January 1988, plant engineering sent support engineering an engineering ];
support request, which identified the problem. In April 1989, support
- engineering generated an action item, which was a plan of action. At the
end of the inspection period, the action item was still in the review
process and system walkdowns were still in progress. The inspectors
discussed with the licensee a concern that corrective actions needed to
correct the drawing errors were not prompt. The licensee stated that .
manpower resources were being used to upgrade the vendor manuals, l
illegible vendor drawings, and design basis documents, which had
priorities over the P& ids. The licensee also stated that the work to
upgrade the P& ids would be completed by the end of the year. The work
scope would include completion of walkdowns, revision of drawings, and
tagging vendor supplied equipment. j
1
I
_ _ _ - - - _ )
_ _ _ _ _
-
- ;
9
No violations or deviations were identified in this area of the
inspection.
6. Monthly Maintenance Observation (62703)
Selected maintenance activities were observed to ascertain whether the
activities were conducted in accordance with approved procedures. The
activities included:
OPMP08-SI-0904, Revision 0, "HHSI Pump A Discharge Pressure
4
Calibration (P-0904)"
PreventiveMaintenance(PM)IC-1-SI-86003948 Revision 2.C, "HHSI
Pump A Discharge Calibration"
PM MM-1-HF-89000869, Revision 0.B. " Fuel Handling Building Exhaust
Fan 11C Discharge Damper' Lube / Inspection"
The' inspectors determined through observations and procedure reviews
that approved procedures were being used, replacement parts were
properly certified. the equipment was properly returned to service, and
.
housekeeping was being maintained. The inspectors also determined that
the technicians were familiar and knowledgeable of the work process and
the documentation was adequate to cover the process.
No violations or deviations were identified in this area of the
inspection.
7. Monthly Surveillance Observations (61726)
Selected surveillance activities were observed to ascertain whether the
surveillance of safety significant systems and components were being
conducted in accordance with Technical Specifications (TS) and other
requirements. The following surveillance tests were observed and
reviewed:
1 PSP 06-PK-0004, Revision 5, "4.16KV Class 1E Undervoltage Relay
Channel Calibration /TADOT-Channel 4," performed on 4.16KV Bus EIA
- 2 PSP 06-DJ0001, Revision 1, "125 Volt Class lE Battery 7 Day
Surveillance Test," performed on Battery E2C11
The inspectors verified that testing was performed using approved
procedures, final test data was within acceptance criteria limits,
housekeeping was maintained by the technicians, and test equipment was
within required calibration cycles. A technical review of the procedures
,
was also performed, with no concerns being identified.
'
No violations or deviations were identified in this area of the
inspection.
,
___--__x.____ _ __ _ _ _ _ _ . - - _ _ _ _ _ .
_ _ _ _ _ _ _
a ,
% , ., _ ~
m . . . ,
,
10 ]
^
8. Startup Test Witnessing and Observation (72302)
Selected Unit 2 startup tests were witnessed to ascertain conformance by
the licensee to procedural requirements, observe staff performance, and
. ascertain the adequacy of test program records. The tests that were
observed included:
- 2 PEP 04-ZG0002, Revision 0, " Loose Parts Monitoring System Baseline
Data"
2 PEPO 4-ZY-0070, Revision 1 " Test Sequence at 75% Power"
2 PEP 04-ZY-0072, Revision 0, "Incore-Excore Detector Calibration"
The inspectors monitored portions of the performance of the vibration and
loose parts monitoring system at the 90 percent reactor thermal power
level utilizing Procedure 2 PEPO 4-ZG-0002. The baseline data procedure
required data to be recorded for a minimum of 10 minutes at the 30-; 50 ,
75 , and 100 percent power plateaus, however, other plateaus were
included. The data were then used to produce power spectral density
signatures at center frequencies of 25 , 250 , 2500 , and 25,000Hz. The
procedure and signoffs were reviewed during and after the testing, as was
the calibration and setup of the equipment.
The data sheets and plots of each channel and frequency were reviewed and
found to'contain the required data. It was noted that two sensors had
become uncoupled from the reactor vessel and had been addressed in Problem
Report 89-113.
The inspectors continued the inspection of progressive testing of
equipment at various power levels in order to verify that the licensee was
correctly implementing the power ascension testing program.
The incore/excore cross calibration was performed at 75 percent reactor
power as specified in Procedure 2 PEP 04-ZY-0070 and as detailed in
Procedure 2 PEP 04-2Y-0072 and Field Change Request (FCR) 89-1510. The
purpose of the test was to determine the relationship between incore and
~
excore axial offset, provide data for calibration of the excore axial flux
difference (AFD) amplifiers,andprovidedatatocalibratetheflux
(Delta = I) penalty to the over temperature, delta temperature protective
setpoints. The test method was as follows:
'*' Obtain a full core flux and thermocouple map with rods out.
Dilute Control Bank D inward and obtain quarter core flux map and
thermocouple map at each 2 percent decrease in AFD.
- Obtain full core flux and thermocouple map at 90 percent of axial
offset negative limit.
. - - _ - _ - - - - __ __ ___-_____ - __ _ _ _ _ _ _
_ -__
t
, .
,
.
I
11
Borate Control Bank D outward and obtain quarter core flux map and
thermocouple map at each 2 percent increase in AFD.
Obtain a full core flux and thermocouple map with AFD at its most
positive value.
On completion of the mapping, the data was reduced by computer to yield
incore/excore detector calibration values.
The inspectors witnessed the test preparation and the data acquisition.
The flux mapping used the standard Westinghouse data collection system with
the six channels recording simultaneously. Each flux det3ctor was fully
inserted and withdrawn. The detectors mapped the full leagth of the core
for each insertion. Each chart was stamped and identified and the data
sheets completed. All data were entered into the plant Proteus Ccmputer
from which further calculations were made for final data reduction and
comparison with test data.
On completion of the test and acquisition, the inspector reviewed the test
procedure for completeness through the step in the procedure that ended
the data collection (Step 6.30). The generated chart data were found to
be adequate in content and reflected the correct flux patterns that were
expected.
No violations or deviations were identified in this area of the
inspection.
9. Power Ascension Test - Plant Trip From 100% Power (72580)
The licensee performed a full load rejection test to demonstrate the
ability of Unit 2 to sustain a trip of the main generator from 100 percent
reactor thermal power. The test was performed using
Procedure 2 PEP 04-ZY-0102, " Plant Trip from 100% Power," Revision 0. The
inspectors witnessed performance of the procedure by the licensee. The
procedure provided instructions to record initial data prior to the plant
trip, to trip the plant, to record post trip data, and to perform a
posttrip review.
l
Pertinent plant parameters were recorded to determine control system
response to the transient. A review of the posttrip data revealed all
acceptance criteria were met. However, two test criteria were not met:
the maximum pressurizer pressure recorded was higher than the initial
value by 41 psig (pressurizer pressure was expected to drop below the
initial value of 2235 psig), and the steam generator level for each loop
failed to drop out of the narrow range band. Subsequent evaluation and
feedback from Westinghouse disclosed that these two criteria had no impact
on the overall acceptability of the test. i
_ _ _ _ _ _ _ _ _ _ _ _ - _ _
,
,
j. .
.
..
3 ~ ;-
12
-
_
X, .
Other observations made during the test included: the reactor coolant
system (RCS) cooled down to SEB*F. 9'F-lower than the no-load value of
"
567'F, because of the slow. closure time of the moisture separator reheater
~ .temocrature control volves; an auxiliary feedwater regulating valve
,s ... indicated partially open while fully closed; and the digital rod position
' indication (DRPI) gave an erroneous flashing. general warning light for a
control' rod.that was full in.following the reactor trip. The licensee and
'
c . Westinghouse reviewed and analyzed the cooldown from 567"F to 558"F. The
'
cooldown was greater.than anticipated, but within the acceptance limits
for the test.
The effect of the Unit 2 trip'was noticed in the Unit 1' control room. A
variation in electrical grid frequency was recorded. Frequency dropped
- from 60 to 59.7Hz, then returned to 60Hz. Several alarms were
momentarily received in the Unit I control room, including inverter
trouble, annunciator ground detected, and plant computer inverter failure
alarms.
A review of Procedure 2 PEP 04-ZY-0102 was performed. The procedure was
compared to licensee commitments, including Final Safety Analysis
Report Section 14.2.12.3.23, " Full Load Rejection Test."
No violations or deviations were identified in this area of the
inspection.
10. Exit Interview
The inspectors met with licensee representatives (denoted in paragraph 1)
on July 6, 1989. The inspectors summarized the scope and findings of the
inspection. The' licensee did not identify, as proprietary, any of the
information provided to, or reviewed by, the inspectors.
L.
_ _ _ _ - - _ - _ _ _ _ _ .