IR 05000445/1993015
| ML20036A963 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 05/11/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20036A962 | List: |
| References | |
| 50-445-93-15, 50-446-93-15, NUDOCS 9305180013 | |
| Download: ML20036A963 (28) | |
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APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-445/93-15 50-446/93-15 Operating Licenses:
NPF-87 NPF-89
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Licensee: TV Electric Skyway Tower
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400 North Olive Street Lock Box 81 Dallas, Texas 75201 Facility Name: Comanche Peak Steam Electric Station, Units 1 and 2
Inspection At: Glen Rose, Texas Inspection Conducted:
March 7 through April 17, 1993 Inspectors:
D. N. Graves, Senior Resident Inspector i
R. M. Latta, Res' dent Inspector R. V. Azua, Resident Inspector
G. E. Werner, Resident Inspector
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W. McNeill, Reactor Inspector D. L. Kelley, Reactor Inspector J. E. Whittemore, Reactor Inspector Accompanying Personnel:
B. E. Holian, Senior Project Manager
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ND Approved:
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L. A. Yandell, Chief, Project Section B Dag '
Division of Reactor Projects
Inspection Summar.y
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Areas inspected (Unit 2):
Routine, unannounced, safety inspections, including plant status, operational
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safety verification, engineered safety feature system walkdown, maintenance
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observation, surveillance observation, initial criticality witnessing, i
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sustained control room observation, startup test witnessing, and followup of previously identified items.
Areas Inspected (Unit 1):
Routine, unannounced, safety inspections, including clant status, operational safety verification, and surveillance observation.
9305180013 930512 I
PDR ADOCK 05000445
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Results (Unit 2):
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The annunciator out-of-service list was not always maintained l
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accurately (Section 2.1.1).
Unit 2 material conditions and housekeeping were determined to be j
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excellent inside containment and good elsewhere (Sections 2.1.2, 2.1.3).
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Station Operations Review Committee (SORC) and Test Review Group-(TRG)
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meetings were appropriately conducted (Section 2.3 and 2.4).
Operator response to operational transients was very good (Section 2.5).
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i Review of the technical disposition of several operations notification
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and evaluation (ONE) forms indicated a lack of generic implications evaluation in one instance (Section 2.8.2).
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The auxiliary feedwater (AFW) system was determined to be available to i
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perform its intended function although one valve was found out of its
expected position (Section 3.1).
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Maintenance activities were appropriately conducted (Section 4).
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Surveillance activities were appropriately conducted although several
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minor deficiencies were noted (Section 5).
j Initial criticality was well conducted (Section 6.1).
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I Sustained control room observation indicated good plant control and
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r conduct by control room personnel (Section 7.1).
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Startup testing was well conducted (Section 8).
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Results (Unit 1):
50RC meetings were appropriately conducted (Section 2.3).
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A surveillance activity was appropriately conducted (Section 5.2).
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r Summary of Inspection Findings:
Inspection followup Item 445/9315-01 was opened (Section 2.3).
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Two noncited violations were identified (Sections 2.8.2 and_3.1).
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Inspection followup Item 446/9260-04 was closed (Section 9.1).
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Attachmen_ts:
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t Attachment 1 - Persons Contacted and Exit Meeting j
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DETAILS
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I PLANT STATUS (71707)
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At the beginning of this inspection period, Unit 2 was in Mode 4 making
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preparations to continue with plant heatup. Mode 3 was entered on March II, 1993, and the reactor coolant system normal operating temperature of 557af and
normal operating pressure of 2235 psig were reached on March 14. Mode 2 entry
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and initial criticality were achieved on March 24.
Low power physics testing was completed, and the plant entered Mode 1 operations on April 6.
Various initial startup tests were performed throughout this reporting period. The main generator was initially synchronized to the electrical grid on April 9.
t Power escalation and startup testing have continued with the plant at approximately 48 percent power at the end of this inspection period. Unit I operated at power in Mode 1 throughout this inspection period.
2 OPERATIONAL SAFETY VERIFICATION (71707,71715,92701)
2.1 Plant Tours i
2.1.1 Control Room Observations
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During the observation of control room activities, the inspectors observed reactor startup to initial criticality (Section 6), initial startup testing (Section 8), and numerous daily activities.
l The reactor operators were observed responding to main control board annunciators. The operators would routinely identify the alarming annunciator prior to silencing the alarm; however, on several occasions, the alarms were silenced prior to scanning the board. All alarm response procedures were
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correctly implemented when appropriate.
On March 25, the inspectors walked down all main control board annunciators and compared the alarms to the Unit 2 annunciator summary list.
The list was i
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found to contain seven annunciators that had not been in the alarm status at the start of the shift. Additionally, six active annunciators associated with l
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the out-of-service Nuclear Instrument N-41 channel were not listed on the sheet. The reactor operator was cognizant of the basis for all the alarm j
discrepancies. The unit supervisor had an extra reactor operator perform an
additional board walkdown to identify the current alarms; however, several of
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the same problems were not identified. This demonstrated a lack of attention j
to detail and can be related to recent Unit I main control board annunciator
problems as detailed in NRC Inspection Report 50-445/93-07; 50-446/93-07.
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A reactor operator and unit supervisor were observed removing
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Clearance 2-92-4247 from the AFW system.
Excellent self-verification and independent verification were demonstrated by the observed personnel.
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Numerous shift turnover meetings were attended and found to be appropriate.
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The off-going shif t supervisor informed the oncoming crew of completed and j
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ongoing evolutions and of the pr voiems encountered during the shif t.
The oncoming crew was briefed on planned shift activities and the focus / goals for l
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their shift.
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f The inspectors reviewed the reactor operator logs and found them representative of plant conditions. Additionally, an independent walkdown of
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-l the main control board emergency core cooling systems verified that these
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safety systems were correctly aligned for Mode 2 operations.
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2.1.2 Containment Walkdown t
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On March 22, 1993, the inspectors accompanied licensee personnel on the final reactor containment building inspection prior _to criticality. The purpose of l
this inspection was to verify that the requirements of Procedure OPT-305, j
Revision 3, " Containment Close-Out Inspection," were properly implemented with
respect to cleanliness controls and containment integrity.
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i Specifically, accessible areas within the containment were examined for the i
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presence of transient combustible materials and system deficiencies including
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valve packing leakage, boric acid buildup, unsecured or loose insulation, scaffolding, and test equipment. With respect to material which was not t
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removed, the inspectors reviewed the licensee's documentation which
established the acceptability of leaving these items in containment.
i Additionally, the inspectors examined the reactor building for evidence of I
loose debris which could be transported to the containment sump and cause pump r
suction restrictions during postulated loss-of-coolant accident conditions. t i
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As a result of this inspection activity, it was generally concluded that the
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material condition of the containment building was excellent, and that work l
controls and access monitoring were effectively implemented. However, the l
inspectors identified several discrepancies which were subsequently addressed
by the licensee. These items included a cable pull rope which had been i
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inadvertently left in a conduit near Junction Box 2C-343 (832-foot elevation),
' boric acid buildup on Valve 2HV-4166 (pressurizer liquia space sample line
isolation valve), and temporary scaffolding installed near Safety Injection-l Accumulator TCX-SI ATAT-03 (832-foot elevation).
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As determined by the inspectors, the cable pull rope was removed in accordance with Work Order 1-93-043551-00 and the conduit seal was properly restored.
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Additionally, based on the review of maintenance work order documentation, it
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was determined that the boric acid buildup on Valve 2HV-4166.had been identified in the licensee's corrective maintenance backlog and that repair activities were being appropriately tracked. _ Relative to the temporary scaffolding installed near Safety Injection Accumulators TCX-03, the licensee a
initiated ONE form 93-914,.which evaluated the existing configuration in j
accordance with Procedure STA-690, Revision 0, " Scaffolding Erection and i
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Based on the technical disposition of the ONE form, the subject scaffolding
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was modified to conform with the requirements of Procedure STA-690 and the
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operability evaluation did not identify any adverse impact relative to the
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original configuration.
2.1.3 Safeguards Building Tour The inspectors conducted routine walkdowns of the safeguards building, and l
plant housekeeping was found to be acceptable.
Several rooms contained
ladders that were in use and not properly tied off.
Other areas contained l
debris left in the room from previous activities. The inspectors noted
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Room 2-33 (steam generator blowdown piping penetrations) had numerous steam
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leaks which were identified with work request tags. Doors $2-10X and S2-12X
'i would not close properly nor remain closed due to malfunctioning latch mechanisms. Operations personnel were informed of these deficiencies and_
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corrective actions were initiated when the condition had not been previously identified.
2.1.4 Radiation Protection Observations e
I The inspectors reviewed activities associated with the implementation of the radiological protection program.
Radiation protection personnel were found to i
be performing Unit 2 surveys on the same frequency as Unit 1 in accordance
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with Procedure RPI-602, Revision 13, " Radiological Surveillance and Posting."
Reviews of Unit 2 surveys, after_ criticality, identified no areas of concern;
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however, the surveys were not posted on all room doors as they_ were in Unit 1 l
and common areas. Through discussion with radiation protection personnel, the I
inspectors determined that the licensee planned to post the surveys at the rooms when either radiation areas or contamination areas are present.
2.1.5 L'ocked Valves The inspectors walked down the Unit 2 locked valve lineups for the safety l
chill water, fire protection water supply, fire pump, and containment spray i
systems.
All valves were in the appropriate positions as listed on the j
associated locked component list.
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i 2.1.6 Conclusions
i Although control room personnel were attentive to the control boards and
knowledgeable regarding current plant status, tho annunciator survey list was
not always maintained accurately.
Shift turnover briefings were found to be
well conducted. The material condition of-the reactor containment building j
was. excellent. Work controls and access monitoring were effectively
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implemented and minor discrepancies identified during the walkdown were
expeditiously resolved. Housekeeping in the safeguards building was-
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acceptable, and deficiencies were either previously identified or promptly-i documented.
Radiation protection surveys were performed as required'and the
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rooms / areas were posted appropriately when_ required. A review of the i
emergency core cooling systems' lineups from the main control board and l
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-7-verification of the locked valve lineups for several systems concluded that all of the implemented systems were in the appropriate status.
2.2 Probabilistic Risk Assessment The licensee submitted to the NRC an individual plant examination (IPE) study in two volumes (See TXX-92387 dated August 28, 1992, and TXX-92490 dated October 1992) and a safety evaluation report will be issued regarding the study. The licensee's IPE of external events study was in progress. and scheduled to be completed in June 1995. Workshops were planned for licensee management addressing how the IPE was developed and its potential uses.
Later workshops were planned for the personnel at the implementation level. There were no organizations currently chartered with applying the IPE data to such activities as surveillance testing, operations, preventive and predictive maintenance, and reliability data collection.
Several reliability improvements have already occurred as a result of the IPE development. One example of such improvements was the use of high temperature lubricants for safety-related motors, thus reducing room cooling requirements.
One member of the IPE development team has been assigned to the site engineering organization. This part-time assignment was to provide assistance in application of the IPE.
It was anticipated by the licensee that there will be additional applications of the IPE by the fall of 1993.
2.3 SORC Meeting The inspectors attended the regularly scheduled SORC meeting on April 14, 1993. Topics discussed included minor modification and procedure change reviews, a Technical Specification interpretation involving the application of Technical Specification 4.0.2 to Specification 4.0.5 surveillances, a plant incident report review involving the reverse flow test failure of Check
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Valve 2AF-0106, a Unit 1 Licensee Event Report 93-04 review regarding two cases of missed surveillances, and a ONE form which documented numerous discrepancies between the Inservice Testing Program, final Safety Analysis Report, and Technical Requirements Manual.
The ONE form largely involved discrepancies in valve numbering and descriptions between the licensing basis documents. The form was forwarded to
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engineering for disposition.
The 50RC appropriately discussed in further detail the potential for other-similar discrepancies which may be present as a result of closing out Unit 2 engineering work.
Engineering reported to SORC-that these type of discrepancies appeared minor and would have been picked up during routine engineering procedures and reviews.
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Licensee Event Report 93-04 had been initially discussed at a previous meeting; it involved two instances where valve stroke times were in the
" alert" range and were not identified for an increased testing frequency.
Discussion of the circumstances of the two events identified that the plant incident report and the licensee event report would have to be revised to more accurately identify the root cause.
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Appropriate questions were raised regarding a safety evaluation describing the introduction of a nitrogen gas " blanket" into the atmospheric drain tank.
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safety evaluation was to be expanded to discuss tank venting capability.
i Standard limiting condition for operation action requirement Form ODA-308-38 i
was discussed, which included a technical evaluation regarding potential j
nonconservative reactor coolant system flow limits.
The revised flow limits
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were calculated when engineering realized that vendor calculations were for
slightly higher reactor coolant system (RCS) average temperature values than
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plant design. The technical evaluation verified that the new procedure
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limits, which are still more conservative than the Technical Specification
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values, have never been exceeded during plant operations.
The SORC questioned i
the adequacy of the procedure change in describing all combinations of flow
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limit, for the various steam pressure / reactor power combinations.
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Additionally, the Procedure Form approval was postponed to determine whether a safety evaluation should be written to evaluate plant operation with the i
slightly nonconservative flow limits. This item will be identified as
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Inspection Followup Item 445/9315-01.
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The Technical Specification interpretation was discussed and approved.
A question was raised regarding whether any other plant similarly applied the
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25 percent " grace" period of Specification 4.0.2 to Code surveillances of greater than a 1-year frequency. That information was not available. The
interpretation was approved by SORC with minimal further discussion. The
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inspectors discussed this interpretation with the Technical Specification i
Branch of the Office of Nuclear Reactor Regulation. Although a formal j
acceptance of this position had not been previously granted by the Office of
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Nuclear Reactor Regulation, it was determined that the use of the i
Specification 4.0.2 " grace" period would be determined acceptable if used in
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accordance with the guidance in the bases, which precludes repeated use for
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convenience.
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Discussions throughout the meeting were generally good and focused on the safety aspect of the issues addressed.
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2.4 TRG Meeting
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i The inspectors attended TRG Meeting 93-025, conducted on March 26, 1993. The l
main topics of discussion were preliminary review and approval of the low
power physics test results and the review of Procedure 150-240B, Revision 1, i
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"50% Reactor Power Test Sequence."
l The meeting was attended and conducted.in accordance with Procedure STA-420, f
Revision 2, " Responsibilities of the Test Review Group." The meeting minutes
were reviewed by the' inspectors and verified to contain all of the information
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required by Procedure STA-420 and that they accurately reflected the content j
of the meeting. The meeting and associated documentation were appropriate and
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no deficiencies were identified.
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2.5 Operational Transients j
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On April 14, 1993, the licensee was maintaining Unit 2 at a power level of
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approximately 28 percent to attain stable core conditions prior to conducting a calorimetric power measurement.
Steam generator water levels were being maintained by automatic operation of the feedwater regulating valves (FWRVs).
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Just prior to 9:54 a.m., the FWRV for Steam Generator 2-02 closed, stopping l
all feedwater flow to the steam generator.
The panel operator became aware of
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the valve position when a Steam Generator 2-02 low level alarm was received
and he verified the FWRV position. After the attempt to manually open the.
l FWRV was unsuccessful, the operator manually opened the FWRV bypass valve to
its full open position.
Additionally the crew coordinated their efforts and
immediately reduced turbine generator load from 230 MWe to approximately
130 MWe. Once the steam generator water level had been restored to the normal l
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band (64-66 percent), load was added to the turbine generator to the limit
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imposed by the fully opened FWRV bypass valve.
The crew was able to reload i
the turbine generator to attain a maximum reactor power level of 26 percent.
I Technicians commenced troubleshooting and determined that a circuit card
associated with the controller for the FWRV had failed, and the card was
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replaced.
The inspectors observed the crew transfer Steam Generator 2-02 level control l
from manual to automatic on the FWRV. This evolution was accomplished l
smoothly with minimal perturbation on feedwater flow rate and steam generator
level. After it was determined that the FWRV would effectively control level
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in automatic, the unit supervisor directed the two panel operators to
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coordinate and restore the turbine generator load to 230 MWe. The desired j
plant conditions were attained and a 24-hour' stability run was commenced.
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Operations personnel initiated a corrective action ONE form to evaluate the
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l card failure and address any generic issues associated with the failure.
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inspectors concluded that the crew's reaction to the transient and the
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j performance of the subsequent restoration were good.
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L Just prior to restoring the Steam Generator 2-02 FWRV to automatic, the Unit 2 turbine control system automatically shifted from " load control" to the " speed control" mode of operation.
Speed control was not the desired mode of I
operation, and the mode shift caused the turbine to assume an additional
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15 MWe of load.
The operators readjusted generator load and shif ted back to
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load control.
Discussions with operations personnel revealed that, when the i
turbine generator had first been loaded on April 9, 1993, it had been f
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necessary to assume a load of 210 MWe in order to shift the system to load control.
The threshold load for attaining the mode shift was determined by
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F the licensee to be excessive.
Additionally, a control system mode shif t had
occurred on April 13, 1993, which had resulted in the rejection of about
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40 MWe of load. Since the original problem, vendor personnel had been-l troubleshooting and the licensee was awaiting results of this effort.
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additional conversation with inspectors, a licensee representative initiated a
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corrective action ONE form to document the event.
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2.6 Containment Spray System Instrument Valve Mispositioned j
On April 13, 1993, during the performance of quarterly operability i
surveillance for Containment Spray Pump 2-03, the licensee noted that the
running pump did not indicate any flow. The licensee initiated a line up
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check and discovered that the high side isolation valve for the pump discharge i
flow Transmitter 2-FT-4774-2 was shut.
Before continuing spray system j
testing, a valve lineup of all containment spray instrumentation was conducted
and no additional discrepancies were identified.
The licensee continued the
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surveillance testing to a satisfactory completion and initiated corrective-l action ONE form 93-893.
The inspectors determined that a cold calibration had been performed on the l
transmitter on February 27, 1993, under Work Order 3-93-315730-01.
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I vaulted work package indicated that the transmitter isolation valves had been opened and verified open at the completion of the work.
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The licensee was evaluating this occurrence in conjunction with previously.
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identified valve mispositionings in an attempt to identify any common issues l
that would assist in formulating an effective corrective action plan.
j Additionally, instrument lineup verifications were performed on the auxiliary j
feedwater, safety injection, and residual heat removal systems, and no i
additional discrepancies were identified.
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2.7 Feedwater Isolation Valve Nitrogen Low Pressure Alarms
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I During a control room walkdown on April 14, the inspectors noted that all four l
control room annunciators for the feedwater isolation valve accumulators i
" Nitrogen Pressure Low" were identified as deficient. These annunciators had
_l been in service the previous day. Discussions with the control room operators indicated that operations and engineering had determined that the Unit 2 l
design was different than Unit 1.
For Unit 2, the pressure switch (which j
actuates the control room annunciator on low pressure) is located outside of a j
normally closed isolation valve.
Unit I has the pressure switch located i
inside the isolation valve, which will warn operators of abnormally low
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nitrogen pressure. The inspectors verified that a ONE form had been written,
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that operators were checking nitrogen pressure on.a local gauge shiftly, and
that the design difference was -listed on the unit difference summary report.
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The inspectors attended the ONE form meeting on April 15.
It appears that the
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pressure switch was located outside the isolation valve fer Jnit 2 because the
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I Unit 2 design was supplied with qualified local gauges, whuh would not need to be isolated during operations. However, these gauges' were not installed.
Instead, gauges similar to Unit I were installed, necessitating the isolation valves to be maintained closed. The ONE form was dispositioned to engineering _
to determine if the qualified gauges could be installed, or if the pressure
switches would need to be relocated. The inspectors discussed with the unit
supervisor the expected frequency for recharging the nitrogen accumulators and i
determined that the shiftly check of the local gauges was acceptable.
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2.8 ONE Form Review I
During this-reporting period, the inspectors reviewed the technical
dispositions of selected ONE forms in order to assess the adequacy of the l
licensee's deficiency documentation and corrective action process.
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2.8.1 Nonqualified Helicoil
.l The inspectors examined the structural analysis associated with ONE-Form 93-483 which documented a deficient helicoil installed in the Unit 2 Steam Generator 4 secondary side 2-inch inspection hole.
As determined by the
inspectors, this deficiency resulted from the installation of an unqualified
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helicoil to repair one of the four bolt holes in the subject inspection hole
cover.
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Based on the review of the referenced ONE form, Design Change Notice 5767, Revision 0, and the supporting analysis contained in Westinghouse's.
i Letter WPT-15157, it was determined that the licensee had established appropriate justification for the "use-as-is" disposition of this one-time
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deviation. This conclusion was predicated on Westinghouse's analysis, which
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demonstrated that the integrity of the theee remaining fasteners was t
acceptable for continued use until the first refueling outage. Additionally, (
the inspectors determined that the specified repair / replacement work activity r
was being tracked on Action Request 93-039768.
Based on the above reviews, it was determined that the licensee had implemented appropriate corrective actions to address the identified l
deficiency.
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2.8.2 Impaired Halon Cylinder l
The inspectors also evaluated the licensee's actions associated with ONE
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Form 93-749, which identified an impaired halon cylinder in the Unit 2 cable
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spread room.
Specifically, during the performance of Procedure MSE-P2-7704, l
Revision 1, "Halon Fire System Test CPX-EIPRLV-42A," as implemented by various
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work orders, the licensee determined that a quarter had been placed between.
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the actuator and the cylinder valve on Cylinder 13. This condition would have l
prevented this cylinder from actuating, which would have reduced the amount of-i halon available from the main bank for fire suppression purposes.
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Subsequent to the identification of this deficiency, the cylinder valve was
_ properly reinstalled and compensatory-fire watches were initiated for the affected areas in Unit 2.
The licensee also performed an evaluation to
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hazards analysis for the cable spread room.
Based on the review of this j
evaluation, it was determined that the reduced quantity of halon agent j
available in the main bank of supply cylinders did not render the system -
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Therefore, the safety i
significance of this specific system related-condition was determined to be
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minor. However, the licensee's initial root cause and generic implications -
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assessment of this condition was limited in that the potential impact of this type of event to have occurred on Unit ] was not considered nor was there an
aggressive attempt to address the deficient work controls which allowed this
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condition to exist.
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Subsequent to discussions with the inspectors, the licensee initiated an
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evaluation of the generic implications for Unit 1, which included the scheduled performance of halon agent supply verification and actuator j
removal / inspection.
As a result of this activity, no additional impairments
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were identified and the halon fire suppression for both units was returned to l
service.
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Based on the results of an interview with the cognizant startup engineer and l
the review of the related construction work documents and design change i
notices, it was ascertained that the quarter was inserted in the subject halon
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cylinder actuator in order to prevent accidental discharge during the onsite j
movement of these components.
Specifically. the protective cap for this
cylinder was missing and, during the construction phase movement of halon
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cylinders, the quarter was placed between the actuator and the cylinder valve
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to preclude inadvertent actuation. However, as determined by the inspectors, this action was not authorized by the governing construction work documents-
nor was it documented.
i In order to evaluate the potential tampering aspects of this event, the licensee initiated a corporate security investigation. The details of this evaluation were reviewed and documented in NRC Inspection Report 50-445/93-17; 50-446/93-17.
Based on the results of this inspection activity, it was determined that the deficient work controls which precipitated this event were
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not intentional nor was there any objective evidence of wrongdoing.
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In conclusion, given the minor safety sigr.ificance of this licensee identified
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j event and the determinaiion that wrong doing was not a factor, this violation
of failure to follow procedures will not be subject to enforcement action
because the licensee's efforts in identifying and correcting the violation j
'
meet the criteria specified in Section VII.B.2 of Appendix C to 10 CFR Part 2.
!
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However, it was noted that the licensee's initial corrective actions were
,
limited in scope and did not consider the potential impact for related systems I
in Unit 1.
This deficiency in the licensee's root cause and generic
!
implication assessment process was considered a weakness in the safety i
assessment and quality verification program.
l
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2.9. Conclusion j
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With the exception of attention'to detail regarding shiftly updating of the j
annunciator out-of-service list, control room activities were appropriately j
'
conducted.
Plant tours conducted by the inspectors concluded that material
!
conditions and housekeeping in the containment was excellent.
Conditions in
!
the safeguards building were generally good, with several leaks, loose j
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material, and malfunctioning doors identified.
Radiation protection surveys j
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were being appropriately conducted with surveys posted where required.
Locked valve lineups were verified to be accurate and current.
The licensee has
,
submitted an IPE that currently receives little application at the facility, l
but more training of licensee staff regarding the development and potential
applications was planned.
50RC and TRG meetings were appropriately conducted.
'
Operator response to the observed transients was very good.
An instrument isolation valve was found mispositioned by the licensee and was being
evaluated in conjunction with other identified valve mispositionings.
A
'
review of several ONE form resolutions concluded that, while generally v
satisfactory, the potential impact of similarly impaired halon bottles on
Unit I was not originally considered.
[
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3 ENGINEERED SAFETY FEATURES SYSTEM WALKDOWN (71710)
!
During this reporting period, the inspectors performed a walkdown of the AFW
.
system in order to independently verify the operational status of the system.
l 3.1 Discussion
!
!
The inspectors verified that the licensee's system lineup procedure conformed
[
to system flow diagrams and the as-built configuration of the AFW system.
The r
inspectors also examined equipment conditions which could adversely affect
plant performance, including the proper installation of hangers and supports, labeling of systems and components, housekeeping, control of combustible materials, and the configuration / material conditions of system valves and components. Additionally, the inspectors verified that the associated process
instrumentation was functioning and that the indicated values were consistent
<
with expected parameters, required support systems were operational, i
associated electrical breakers were properly positioned, and the control room
!
indications matched the actual system configuration.
!
In order to confirm the operational status of the AFW system, the inspectors
'
utilized the applicable sections of Procedure 50P-304B, Revision 1, " Auxiliary
,
Feedwater System," and Flow Diagram M2-0206, " Auxiliary Feedwater System."
l The inspectors also utilized the results of NUREG/CR-5831, PNL-7783,
!
" Auxiliary Feedwater System Risk-Based Inspection Guide for the Comanche-Peak l
-
Nuclear Power Plant," dated October 1992 and the criteria contained in AFW l
Design Basis Document DBD-ME-206, Revision 6, to confirm the installed system i
configuration and status control.
[
!
.
Based on the results of this walkdown, the inspectors determined that i
'
Procedure SOP-304B properly incorporated the required positions for locked
{
valves and that supply breakers and hand switches were in the proper position
for standby readiness.
During the verification of valve position indications
!
in the control room, operations personnel were knowledgeable of system status
!'
and operational conditions.
,
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Relative to the areas inspected, cleanliness controls and housekeeping were
!
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j very good and proper radiological measures were effectively implemented.
j System and component labeling was determined to be superior and as confirmed j
during the performance of field inspections, all of the enhanced labels
accurately reflected the descriptions in the governing system operating l
procedure.
!
During the conduct of this walkdown, the inspectors observed excessive leakage from Valves ZAF-2460, 2AF-2462, 2AF-0124, and 2AF-0141, which were located in
!
the turbine-driven AFW pump room. This condition was also identified by the
!
licensee's health physics personnel who initiated prompt action to contain the
leakage and generate corrective maintenance work orders. The inspectors also
>
identified an oil leak on the gear operator for Valve 2AF-0090, the AFW Pump A discharge line cross connection isolation valve.
This condition was l
identified to operations personnel and a corrective maintenance work order was
!
initiated.
l
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Additionally, the inspectors identified a discrepancy in the actual position
of Valve 2AF-0108, one of the condensate transfer Pump CP-AFAPCT-01 suction l
isolation valves. Specifically, this valve, which is required by-i Pr.cedure 50P-304B to be closed, was determined to be open.
Subsequent to the i
o identification of this procedural noncompliance, the licensee initiated ONE
,
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Form 93-826 to document this condition and provide a technical disposition.
I Based on the review of this ONE form, it was determined that on March 21, 1993, Clearance 2-93-01323 was removed and the valve was incorrectly l
repositioned to the open position because the clearance release utilized the j
i restoration requirements of Procedure SOP-303B, " Condensate System,"
l Attachment 2, rather than Procedure SOP-304B, Attachment 1.
!
Although this occurrence was. contrary to the requirements of l
Procedure 0WI-0110, which states that the release of a clearance should be in
accordance with the normal procedural operating position, the ramifications of-
!
this specific event were determined to have minor safety significance.
j Therefore, given the minimal safety significance of this event and the prompt corrective actions initiated by the licensee, this violation involving a
.
failure to follow procedures is not being cited because the criteria specified (
'
in Section VII.B.1 of Appendix C to 10 CFR Part 2 have been met.
l l
]
-3.2 Conclusions
.
!
Relative to the areas inspected, the licensee's locked valve program was
!
!
determined to be properly established with excellent system and component labeling in place. Housekeeping and cleanliness controls were very good-and
'
radiological programs were effectively implemented. Although one noncited
'
violation was identified involving an incorrectly positioned AFW valve, the
!
system alignment would have allowed the system to perform its intended
[
function.
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4 MAINTENANCE OBSERVATIONS (62703)
4.1 Main Feedwater Pump Turbine Overspeed Testing
The inspectors observed Test PPT-P2-2029B, " Main Feedwater Turbine 2B Overspeed Trip Test," Revision 1, with Procedure Change Form 1 on March 29,
,
'
1993.
This test was originally terminated because of a steam leak and was restarted on March 30, 1993. The procedure contained the proper review and
approval signatures, and test personnel received the required approvals bef ore
!
test initiation. Appropriate prerequisite plant conditions were established
,
prior to the test.
The test personnel were knowledgeable. The collection of test data was
!
I complete and accurate. Communications between operations and test personnel were excellent.
Independent Safety Engineering Group (ISEG) personnel were
,
observed witnessing the test. No difficulties were experienced in the performance of the test.
Restoration of the system to service following i
completion of the procedure was performed without incident.
4.2 Borg-Warner Check Valve Repair
!
During back-flow testing of several AFW check valves, Valve 2AF-106, which is the check valve between the turbine-driven AFW pump and Steam Generator 4,
'
'
failed to meet its acceptance criteria.
The valve was radiographed and
'
determined to be slightly open. The valve was subsequently disassembled, and
!
the valve internals were disassembled and reworked to decrease the spacing
between the various moving parts.
The inspectors observed portions of the valve inspection, machining, welding, and nondestructive testing. No specific cause for the failure could be determined at this point. The valve was
'
reassembled in accordance with Work Order 1-93-041068-00 and retested in accordance with Work Order 5-93-502205-AA. The inspectors observed these
!
activities, and again the valve failed its reverse flow test.
Additional investigation by the licensee determined that the valve bonnet was misaligned l
and that the valve disc was not parallel to the seating surface.
The cause of
!
the misalignment was determined to be the mispositioning of an external slot
_
'
and key device that had been originally installed to prevent valve bonnet misalignment.
The corrective actions associated with this event are addressed
',
in NRC Inspection Report 50-445/93-16; 50-446/93-16.
The activities observed by the inspectors, including valve disassembly, machining, welding, t
'
reassembly, and testing, were well conducted and controlled, and no work
control or performance deficiencies were identified.
4.3 Component Cooling Water Heat Exchanger Cleaninq
,
,
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The inspectors observed preventive maintenance activities related to the i
cleaning of Component Cooling Water Heat Exchanger CP2-CCAHHX-01.
This
!
preventive maintenance was performed as a result of unacceptable heat
,
exchanger thermal margins identified by the licensee as part of the fouling j
factor monitoring program.
Limiting condition for operations action i
requirements were met for Technical Specification 3.7.3.
Hydrolazing of the
[
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t heat exchanger tubing was performed in accordance with Work
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Order 3-93-321899-01. Maintenance Procedure MSM-CO-5877, Revision 0,
" Component Cooling Water Heat Exchanger," with procedure change Form I was
[
also utilized in the work order. The required administrative approvals were i
obtained and clearances installed prior to initiating work. The craft personnel were knowledgeable of the task and qualified to perform the work.
The work order provided quality control hold points and quality control
!
personnel were observed witnessing this activity.
i 4.4 Conclusion The observed maintenance actions were determined to be properly authorized and l
well conducted. All Technical Specification limiting conditions for operation l
were entered and complied with as required.
Nuclear oversight department t
personnel were observed to be present and involved in field activities.
'
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5 SURVEILLANCE OBSERVATIONS (76726)
l
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Selected surveillance activities were witnessed by the inspectors in order to l
determine whether the observed activities were being conducted in accordance
with Technical Specification and other administrative and procedural
'
requirements.
!
,
The inspectors observed the performance of Sections 8.3.1 of Test Procedure OPT-203B, " Residual Heat Removal System " Revision 1.
Several steps
[
in the procedure indicated that pump suction pressure should be less than
'l 40 psig as measured on Indicator 2-PI-0601, which had a range of 0 - 800 psig.
At Step 8.3.1.Y, the operators continued with the procedure although the
suction pressure indicated greater than 40 psig. The inspectors subsequently
"
determined that the failure to meet this step had no impact on the test
.
results, which were satisfactory.
!-
I Prerequisites to the test were verified complete, authorization and approach
for test initiation were appropriately obtained, the collection of test data
by test personnel was complete and accurate, and good communication was
!
observed between operators and test personnel.
j
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5.2 K609 Slave Relay Actuation Test
!
i On April 15 the inspectors observed the performance of Procedure OPT 467A,
" Train A SFGDS Slave Relay K609 Actuation Test," which starts Unit 1 emergency s
Diesel Generator 1-1.
The control room briefing conducted by the unit
!
supervisor was thorough and professional.
The reactor operators discussed the i
procedure with the auxiliary operators and performed the procedure correctly.
'
There was one discrepancy noted as a result of the test:
the positive
displacement charging pump suction stabilizer vent valve (1/1 8202A) closed, i
as designed, but reopened when the actuation was reset (versus being manually
opened, per design).
The same valve had failed during the previous l
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performance of this test and had been worked under Work Order 1-93039382-00.
The unit supervisor properly annotated this discrepancy on the procedure and discussed the failure with the shift supervisor.
The failure was
,
subsequently determined to be a valve indication problem, and the valve was j
actually positioning correctly. A design modification, DM 93-0046, had been
>
proposed to modify the valve's indication to function more reliably.
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5.3 Safety Injection i
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The inspectors observed the performance of Section 8.2.1, Procedure OPT-2048,
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"SI System," Revision 1.
The performance of this test was interrupted by a
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fire drill. Operator response to this interruption was appropriate.
The
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inspectors observed that a 0-3000 psig test gauge was utilized instead of the l
0-2000 psig gauge indicated in the procedure.
The inspectors verified that (
the substitution was allowed by Procedure ODA-407, " Guideline on Use of
}
Procedures," Revision 4.
This test was also intended to. satisfy the in-
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service testing requirements for the safety injection pumps.
The recorded pump differential pressure exceeded the specified action limit and was i
documented appropriately. The work package did not contain the pages with the
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applicable system res' oration steps, but the operator used the control room
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file to obtain the procedure and perform the system restoration. General test l
conduct and execution, including communications, were good.
t t
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5.4 Analog Channel Operational Tests
!
On April 7, 1993, the inspectors monitored portions of the instrumentation and l
controls personnel's performance of several analog channel operational tests.
These tests were performed in accordance with Procedures INC-7654B, "ACOT and j
Channel Calibration Pressurizer Level"; INC-7724B, "ACOT and Channel Calibration Pressurizer Pressure"; and INC-7857B, "ACOT and Channel Calibration Containment Pressure and Channel Calibration Containment Wide Range Pressure."
l i
The inspectors reviewed the surveillance procedures for clarity and technical j
adequacy.. The procedures had been reviewed and approved, as indicated by.the i
appropriate signatures. Overall, the procedures were found to provide good f
step-by-step instructions, delineating the order in which data was to be
'
collected. However, it was identified during the performance of the pressurizer level channel test that Procedure INC-7654B failed to provide a
,
complete posttest return-to-service checklist.
This was identified by the
!
control room operator, following completion of the test, when the operator
!
questioned the instrumentation and controls technician as to wSen he should
return the control board instrumentation, previously realigned for the test,
!
back to its normal operating position. The instrumentation and controls j
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technician reviewed the report and identified that it was not addressed.
The i
operator and the technician both verified that all the appropriate control i
board instrumentation and other equipment were returned to the pretest j
condition.
As a result, the technician wrote a procedure change notice to
correct the error. A review of the other two procedures did not identify any l
l similar errors.
The inspectors, upon reviewing the procedures, noted that the Y
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procedures depended on the skill of the craf t, for they did not instruct the instrumentation and controls personnel on how to assemble or operate the equipment used to gather the data needed. A review of the licensee's training r
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records indicated that the instrumentation and controls personnel involved in performing these survei' lances had the proper qualifications.
The instrumentation being used to acquire data for these surveillance tests
!
were within their calibration cycle, as noted by the attached calibration
stickers. This was further verified through a review of the material and test
equipment records.
During the performance of the surveillance tests, i
excellent procedural compliance was observed, with good communication being
'
maintained between the technicians and the control room operators.
r 5.5 Other Surveillances
.
t The inspectors observed portions of Procedures OPT-4928, " Train B Safeguards
Slave Relay K610 Actuation Test," Revision 1, on March 29; and OPT-201B,
,
" Charging System," Revision 1, on March 19.
Both procedures were j
appropriately conducted with proper authorization and approvals; limiting
,
condition for operations action requirements were implemented when required; i
communication was good between operations and test personnel; system
'
restorations were appropriate; and ISEG personnel were also observed witnessing test performance.
j
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5.6 Conclusions
'
c Excellent procedural compliance and good communication between control room
operators and test personnel were observed. The surveillance procedures were
found to be satisf actory and within the skill of the craft. Data collection was complete and accurate, and deficiencies were appropriately documented.
l The inspectors noted that the instrument technician did not display the same
!
questioning attitude displayed by the control room operator in that they i
failed to notice that the positest return-to-service checklist was incomplete.
Nuclear oversight department personnel were observed in the field witnessing
'
a the performance of several surveillances.
,
!
6 INITIAL CRITICALITY WITNESSING (72592)
i The objectives of this inspection were to evaluate the licensee's conformance to license and procedural requirements, ascertain the adequacy of test records
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and results, and observe the performance of operations personnel during i
initial reactor startup.
l The inspectors reviewed Technical Specification requirements, mode restraint l
checkoff lists, calibration of nuclear instrumentation, control room logs, and
!
prerequisites associated with various plant procedures and independently i
verified estimated critical positions. Through sustained control room i
observations, the inspectors maintained cognizance over plant status during i
i and after the initial approach to criticality.
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6.1 Discussion
!
On the morning of March 23, 1993, the inspectors commenced continuous
observations of control room and other activities associated with Unit 2 initial reactor startup. The inspectors attended the briefs conducted for different crews on Procedures 150-101B, Revision 1, " Initial Criticality and i
Low Power Test Sequence"; and NUC-106B, Revision 0, " Initial Criticality."
The test sequence was thoroughly discussed as well as the prerequisites and precautions and limitations associated with both procedures.
The briefs were
'
given by the test engineers with operational limitations and precautions f
provided by the unit supervisors. An emphasis was placed on safety and
!
control of the evolutions.
The inspectors found the briefs to be excellent,
!
with questions being asked by all participants.
Coordination between the test
group and operations was stressed to ensure that the operators were not
!
distracted and all equipment manipulations were directed through the unit i
supervisor.
l I
The reactor startup was conducted using two governing procedures.
Procedure ISU-101B was the sequencing document for initial criticality and all i
zero power physics testing. This procedure was used to ensure that the
!
correct sequence of testing was conducted.
Procedure NUC-106B was the i
procedure used to achieve initial criticality in a deliberate and controlled
.
-
Both procedures were reviewed by the inspectors to ensure that all
!
i manner.
prerequisites had been completed prior to initiating reactivity changes.
l The inspectors reviewed the estimated critical position calculation worksheet
{
and verified the estimated critical position was accomplished in accordance
!
i with Procedure OPT-308, Revision 2, " Calculating Estimated Critical
!
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Condition." Additionally, the inspectors calculated an estimated critical position which yielded the same estimated critical boron concentration. On l
<
March 24, with all rods out with the exception of control Bank 'D' at
!
180 steps, the operators commenced dilution to criticality.
The dilution rate j
>
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was administratively limited to 34 part per million (ppm)/ hour (br) and then reduced to 21 ppm /hr when boron concentration was within 100 ppm of estimated i
critical concentration. At 8:42 p.m. CST, the Unit 2 reactor was determined
!
to be critical.
During the course of the inspectors' observations leading up to criticality,
additional operational activities were observed including:
Entry into and out of Limiting Conditions for Operations j
Starting and stopping of equipment j
+
Response to control board annunciators
{
Communications
{
,
The operators response to these activities were found to be appropriate.
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6.2 Conclusion j
!
Control room operators were found to be very attentive to control board
,
instrumentation and operated equipment in a slow and deliberate manner.
,
Notable performances were demonstrated by the reactor operators and unit supervisors. Outstanding command and control of Unit 2 operations were utilized by the unit supervisors.
7 SUSTAINED CORTROL ROOM OBSERVATION (71707, 71715, 72302)
[
This activity was performed during the period between April 8 and 10, 1993, to evaluate the licensee's control room and plant performance over a sustained period by continuous, long-term inspector observation of control room
,
activities. Observed activities included various startup tests, initial
{
turbine generator startup and synchronization, and various related activities.
,
)
7.1 Discussion
!
The inspectors observed portions of the performance of test
-
Procedures 15U-207B, Revision 1, " Steam Generator Level Control Test," and, i
150-205B, Revision 4, " Dynamic Automatic Steam Dump Control." Testing
!
'
activities were performed in accordance with the referenced procedures and the
,
associated plant operating procedures. Deficiencies identified during testing activities were properly documented for evaluation by engineering. Although
,
the observed activities were acceptably performed, the inspectors observed l
that the reactor operators were informal in their communications, especially l
with regard to annunciators.
Information between the test personnel and the
,
control board operators was not always effectively communicated, as evidenced i
by the operators not knowing why they were being directed to start a second
,
main feed pump during main steam dump valve testing. These observations were
brought to the attention of the shift supervisor and the inspectors subsequently noted considerable improvement in formality and crispness of l
~
communications throughout the remainder of the sustained observation period.
}
The inspectors observed the licensee's efforts in preparation for the initial roll of the turbine.
Control room operator efforts were governed by Power
T Operations Procedure IPO-003A, " Power Operation," Revision 9.
The inspectors noted that throughout the evening of April 8, and the early morning of
,
April 9, traffic of personnel through the control room was minimal, except for
!
the presence of the personnel involved in performing this activity. Despite
[
initial delays in beginning this effort, operations personnel performance was i
'
found to be good.
Procedural compliance was excellent, and communications between the control room and locally stationed personnel were good. The shift
!
supervisor was observed providing nonintrusive support to the unit supervisor i
and the balance-of-plant operator.
-
t Due to the large number of persons attending the initial turbine startup l
pretest briefing, the unit supervisor elected to hold the briefing outside of
the at-the-controls area of the control room.
Access to the control room was i
well controlled by the unit supervisor throughout the evolution. The briefing I
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was conducted by the turbine vendor representative and included discussion of l
various personnel duties and responsibilities, expected equipment performance, i
precautions, operating limits to be observed, and corrective actions to take i
should specific limits be exceeded. Subsequent briefings conducted by the l
shift supervisor regarding turbine overspeed testing were excellent.
Crew members were reminded of the importance of good communications and self-
verification. The turbine startup, including the overspeed test and turbine
stop and control valve testing, was well performed.
!
,
Shift turnover meetings were thorough and informative.
For example, the shift
~
,
turnover meeting prior to the anticipated generator synchronization was
excellent. The shift supervisor discussed the evolutions expected to occur j
during their shift, and the unit supervisor discussed the precautions and i
limitations associated with manipulations of the turbine controls with regard
I to potential mode changes.
l Preparations for generator synchronization were good. The machine was
{
prepared for synchronization in accordance with Procedure IPO-003B, " Power i
Operations," Revision 0.
Following the initial closing of the generator
!
output breaker, the main generator tripped on reverse power. The machine was
synchronized again and also tripped on reverse power during two subsequent i
attempts. Troubleshooting determined that one of the two parallel reverse i
power trip relays was faulty and was removed.
Following the fourth, and
successful, synchronization to the grid, the operator on the turbine control
!
panel rapidly loaded -the generator to approximately 100 Mwe to ensure that the j
machine did not trip on a valid reverse power signal. The 100 Mwe load i
'
assumed is significantly higher than-the amount of load normally assumed
' l
<
following synchronization (approximately 30 Mwe).
This resulted in RCS t
average temperature decreasing below 551 F, the minimum temperature for
[
criticality allowed by Technical Specification 3.1.1.4.
Actions were
immediately taken to restore the temperature above 551of within the 15 minutes
!
allowed by the specification. Temperature was below 551of for approximately
10 minutes and the limiting condition for operation was exited when I
temperature was restored above 551*F. Additionally, as a result of the
}
.
decrease in RCS temperature, pressurizer level decreased to 17 percent, which
{
caused an isolation of the letdown system. The operators immediately entered Abnormal Operating Procedure ABN-104, " Chemical and Volume Control System i
-
Malfunction," Revision 5.
Response by the crew to the event was outstanding.
t An extra senior operator and reactor operator assisted the board operators in i
the restoration of letdown.
The unit-supervisor and shift supervisor i
oversight and control of the restoration was excellent.
l
!
On several occasions during-this_ observation period the operators observed i
that the temperatures in the AFW pump lines to the Steam Generators 1 and 4 l
'
were increasing, indicating that-the discharge check valves, 2AF-0078 i
and 2AF-0106, were not seating fully. Abnormal Operating Procedure ABN-305,
!
" Auxiliary Feedwater System Malfunctions," Revision 3, was entered and '
!
'
utilized several times during the observation period to reduce +he line f
temperatures below 150of.
The two check valves were radiographed and l
l determined to be hanging slightly open. Venting upstream of the check valves j
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i caused the line temperatures to decrease, indicating that the valves would i
seat under high differential pressure conditions and, thus, the slight back j
leakage was not a safety concern.
The operators were attentive and responded
appropriately to the increased temperatures in the AfW lines.
l 7.2 Conclusion
[
Although some instances of informal and/or incomplete communications between operators were observed, in general, communications between operators and test personnel were good. Operators were cognizant of plant conditions at all times.
Command and control exhibited by the shift supervisors and most of the t
!
unit supervisors during testing, routine operations, and abnormal conditions was excellent. The operators displayed a questioning attitude toward the test
procedures and required justification or explanation from test personnel when the procedure intent or goal was not clear.
The reactor operators responded
'
well to abnormal conditions, and additional personnel were quick to assist
during these conditions.
Pretest and shift briefings were thorough.
8 STARTUP TEST WITNESSING (72300, 72302)
The objectives of this inspection were to evaluate the licensee's conformance to license and procedural requirements, ascertain the adequacy of test records l
and results, and observe the performance of operations personnel during
'
initial reactor startup.
,
!
8.1 Low Power Physics Testing
.
The inspectors verified that minimum Technical Specification manning levels
were present in the control room prior to and during the performance of zero power testing. Technical Specification requirements were also reviewed and no
,
discrepancies were identified. The licensee had entered into special test exceptions, Technical Specification 3.10.3, " Physics Tests," which allowed r
.
certain Technical Specification requirements to be suspended during the
'
performance of physics tests. All required action statements and surveillance
requirements were adhered to during the special testing.
l The inspectors attended crew briefings for numerous physics test procedures.
.
Overall, the test briefings were good.
Initial conditions, precautions and
limitations, and expected primary parameter changes were discussed.
Shift
turnovers between operating crews and test personnel were determined to be
appropriate.
{
All or portions of the following tests were observed by the inspectors:
[
'
Procedure NUC-109B, Revision 5, " Determination of Core Power Range for
Physics Testing"
,
i Procedure NUC-120B, Revision 3, " Rod Swap Measurements"
!
e i
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-23-Procedure 150-101B. Revision 1, " Initial Criticality and Low Power Test
Sequence" Procedure ISU-202B, Revision 0, " Calibration of Feedwater and Steam Flow
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Instrumentation at Power," Section 11.1 Procedure 150-2048, Revision 0, " Operational Alignment of Nuclear
Instrumentation," Section 11.1, " Initial Overlap Data Acquisition" All test prerequisites and initial conditions were met prior to commencing the tests. The inspectors verified that monitoring equipment had been calibrated and was set to a common time base. The initial test results were reviewed and the test criteria were met. Coordination and communication between control room operators and test engineers were good.
8.2 Pressurizer Spray ant _ 2ater Capability The inspectors observed Sections 11.1 and 11.2 of Initial Startup Test Procedure 15U-021B, " Pressurizer Spray and Heater Capability," Revision 1, with Procedure Change Form 1, on March 15 and March 16, 1993. The purpose of this test was to establish the throttle positions for the pressurizer spray manual bypass valves and verify the effectiveness of the pressurizer spray.
The procedure was verified to be the latest revision and test personnel received the required approvals before test initiation.
Prerequisite plant conditions were established prior _to test initiation.
Technical Specifications were determined to be met.
The test personnel were knowledgeable and qualified, and their collection of test data was complete and accurate. Communications between operations and test personnel was good.
This test was also observed by the ISEG. The test was conducted in accordance with the administration requirements of
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Procedure STA-812, " Conduct of Initial Startup Testing," Revision 2, and the test procedure. ONE form 93-724 was initiated to document the failure of the Loop 4 low temperature alarm (T0484A). This test was later repeated because, in a subsequent data review, the computer print out did not indicate an event mark for the start of the transient.
The inspectors noted several weaknesses in test procedure writing and review.
For example, Step 11.1.2.10.2 of the test procedure required equilibrium to be established when the spray line indicated less than a 1 F temperature change.
However, one of the three indicators used, 2-TI-411A, was found to read in 2 F increments.
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Step 11.2.8 of the test procedure required the unit supervisor to collect data during the test transient according to Procedure OPT-407, "RCS Temperature and Pressure Verification." The control room operators were already following -
Procedure OPT-407 in collecting data prior to and following this test at 30-minute intervals. However, the test transient duration was only a few i
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minutes, hence, data was not collected during the test transient.
The data i
collected by Procedure OPT-407 was not used for the test.
Step 11.2.2.18 of the test procedure required the operator to collect data
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after system pressure had stabilized. However, there was no definition of i
stabilization in the procedure.
Technical Specification 3.4.4, " Relief i
Valves," l-hour action statement had been entered prior to stabilization j
because the Pressurizer's Power Operated Relief Valve (2-PCV-0456) had been i
manually blocked. Notes in the procedure said the steps should be performed l
expeditiously and the blocked valve should be returned to a normal operating l
configuration. The lead test engineer used his judgment to determine when pressure was stabilized.
The test performance did not appear to suffer because of these procedure weaknesses which were discussed with the licensee.
The licensee indicated t
that the inspectors' comments would be considered in the review of any j
additional startup procedures generated in the future, j
8.3 RCS Flow Coastdown Test Specifically, the inspectors witnessed the conduct of Initial Startup Test
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Procedure ISU-024B, Revision 0, " Reactor Coolant System Flow Coastdown Test."
t The purpose of this procedure was to determine the RCS core flow decay rate, I
at hot standby conditions, following a simultaneous trip of all four reactor
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coolant pumps. Additionally, this test was performed to confirm the delay.
times associated with Final Safety Analysis Report Chapter 15.3 assumptions
for the loss of flow accident analysis.
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Prior to the conduct of this test, the inspectors verified that the specified
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prerequisites were properly performed and that the precautions and limitations associated with this activity were correctly established. The inspectors also
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verified that temporary test equipment was properly installed and calibrated
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and that appropriate provisions had been established for resetting RCS flow in
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accordance with Technical Specification Section 3.4.1.4.
With respect to the
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performance of this test, the inspectors witnessed the lifting of the leads in
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the nuclear instrumentation system racks, which simulated reactor power above j
the P-8 permissive setpoint and verified that the associated permissive t
annunciator was off. Additionally, the inspectors verified that the specified
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i RCS boron concentration and loop flow rates were properly established.
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During the performance of this test no deficiencies were identified and, based i
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was determined that this activity was effectively accomplished in a well controlled manner.
8.4 RCS Leakage Rate Test l
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The purpose of this test was to determine that the reactor coolant leakage f
rate was within the limits prescribed in the Technical Specifications.
The
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h limits were 1 gpm of unidentified leakage and less than or equal to 10 gpm of f
identified leakage.
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The test was performed using the unit common Surveillance Test
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Procedure OPT-303, " Reactor Coolant System Water Inventory." The normal surveillance specifies a 2-hour period for the test. The initial startup test i
modifies this time span to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The inspectors monitored the test data
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for abnormal trends.
None were identified.
The inspectors recorded several i
data points during the 4-hour period and performed independent leakage
calculations. The inspector's independent results were within the_ Technical i
Specification limits. The inspectors also reviewed the licensee's final
leakage rate results and found them to be within the. testing acceptance
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criteria.
The inspectors observed that the test conditions were very
precisely controlled in accordance with Startup Test Procedure I50-0228,
" Reactor Coolant System Leakage Rate Test."
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8.5 Hot Control Rod Operability Testing The purpose of this test was to:
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t Perform an operational check of each control rod drive mechanism with a
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rod cluster control assembly attached,
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Determine the drop times of each rod mechanism, demonstrate proper i
deceleration of the control rods in the dashpots, and
Verify normal rod speeds, movement direction, bank overlap,
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indication, and normal mode operation.
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The inspectors observed the hot control rod tests for Control Banks B and C t
and Shutdown Banks C and D.
The tests were performed at normal operating
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pressure and temperature in accordance with Startup Test Procedure 150-027B,
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" Hot Control Rod Operability Testing." The inspectors noted that all the test equipment was within its current calibration period.
Prior to the performance
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of the drop tests for Shutdown Banks C and D, licensee technicians adjusted the stepping speed for the shutdown banks.
The inspectors reviewed the Work Order 1-93-040388-00 and verified that the test instrument calibrations were
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within the current period. The work was performed in a professional and l
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precise manner. The inspectors examined the recorder traces of the rod drop tests and, using stepping sequence comparison templates, noted that the test i
traces and templates matched very closely.
The tested rod drop times were
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within the limit specified in the Technical Specifications.
The test engineer
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appeared very knowledgeable of the rod control system and the testing
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procedure.
Communications had been established between the rod control
panels, the Unit 2 reactor containment building, and the control room for the i
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test. The inspectors observed that the communications were effective and maintained at all times when required.
The inspectors also noted that an ISEG representative was performing an independent oversight cbservation of the
test.
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i All the acceptance criteria were met.
The testing was well controlled and the f
performance was professional.
The personnel involved were very knowledgeable of the test and the rod control system.
t 8.6 Loose Parts Monitoring Baseline Data
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The purpose of this test was to obtain baseline data from the loose parts monitoring system from the unit precritical condition through the various power plateaus to 100 percent power.
During this inspection period the inspectors observed portions of the
precritical baseline testing of the loose parts monitoring system in i
accordance with Startup Test Procedure ISU-211B, " Loose Parts Monitoring
.i Baseline Data." The majority of the observations were made with four reactor
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coolant pumps running.
During the licensee's testing, two detectors were
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found to have failed.
Replacement detectors were subsequently installed and satisfactorily tested.
The loose parts monitoring testing will continue through the various power plateaus to 100 percent power.
The portions of the
testing activities observed by the inspectors were well coordinated and i
professionally performed.
8.7 Operational Alignn.cnt of process Temperature and N-16 Instrumentation i
The purpose of this test was to align the N-16 and process temperature instrumentation prior to initial critically and at various power plateaus during power ascension. The inspectors observed portions of the comparison of
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the active cnid leg narrow range resistance temperature detector amplifier to i
the spare cold leg resistance temperature detector.
Several circuit tests and
resistance readings were recorded before the comparison was completed.
Portions of this test will be performed at various power plateaus during power J
I ascension. Those portions observed during this reporting period were accomplished in a professional manner in accordance with Procedure 150-2268,
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" Operational Alignment of Process Temperature and N-16 Instrumentation.
8.9 Conclusions The observed testing activities were well conducted by operations and test personnel. The individuals involved were knowledgeable regarding the tests.
Communications, including pretext briefings, were very good.
Test equipment
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was properly calibrated and data collection was accurate. Deficiencies were
documented properly. Although several minor procedure weaknesses were noted.
l testing was not impacted, and the procedures were generally well written.
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9 FOLLOWUP (92701)
9.1 (Closed) Inspection Followup Item 446/9260-04:
Abnormal Operating Procedures (ABNs) Procedural Adequacy Verification l
As previously documented in NRC Inspection Report 50-445/92-60; 50-446/92-60,
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both technical and administrative errors were identified in various ABNs.
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I response to this issue, the licensee initiated a program to verify the l
adequacy of ABNs that included comparison of procedure nomenclature with field
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noun descriptions used and field walkdowns.
This activity was divided into-J groups of ABNs that would require review before entry into various modes.
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To assess the adequacy of these corrective actions, the inspectors examined a j
selected sample of ABNs that were designated for completion prior to Mode 2 l
ent ry. The ABNs designated to be reviewed prior to entry into Mode 4 were
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addressed in NRC Inspection Report 50-445/93-11; 50-446/93-11.
The following
ABNs were reviewed to determine if the administrative enhancements and
technical corrections identified during the licensee's review process had been
properly incorporated:
ABN-302, Revision 3. "Feedwater, Condensate, Heater Drain System
Malfunction" i
ABN-703, Revision 4, " Power Range Instrumentation Malfunction"
ABN-707, Revision 4, " Steam Flow Malfunction" l
ABN-708. Revision 4, "Feedwater Flow Instrument Malfunction"
ABN-912, Revision 2, " Cold Weather Preparation / Heat Tracing and Freeze i
Protection System Malfunction" i
i Based on inspection of the results of the licensee's reviews and field
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verifications, and the verification of the incorporation of the findings into the referenced procedures, the inspectors determined that the licensee's
review process associated with Unit 2 ABNs was effectively implemented.
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ATTACHMENT
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1 PERSONS CONTACTED t
1.1 TU ELECTRIC
i D. Allen, Initial Startup Test Manager A. Bechem, Initial Startup Test Engineer
- M. Blevens, Director of Nuclear Overview i
H. Brau, Operations Support Supervisor
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W. Brown, Field Support Supervisor
- W. J. Cahill, Jr., Group Vice President
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R. Calder, Site Reactor Engineering Manager i
- R. R. Carter, Assistant to Maintenance Manager
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J. Dillard, Reactor Operator
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- J. W. Donahue, Manager,.0perations
T. Guarino, Initial Startup Test Engineer
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L. Haley, Operations Support Specialists
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H. Hamzehee, Risk and Reliability Engineer l
- T. L. Heatherly, Licensing Engineer
- T. A. Hope, Site Licensing Manager A. Husian, Reactor Engineering Director i
R. Jurrus, Surveillance Engineer
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- J. J. Kelley, Jr., Vice President, Nuclear Operations E. Mack, Test Engineer
- D. M. McAfee, Manager, Quality Assurance i
J. McMahan, Surveillance Engineer
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L. Meller, Reactor Operator P. Passalugo, Civil / Structural Supervisor
M. Piloian, Initial Startup Test Engineer
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D. Rector, Reactor Operator D. Ross, Unit Supervisor S. Sewell, Unit Supervisor i
i A. Shedlosky, Operations Support Specialist
- L. L. Terry, Vice President Nuclear Engineering and Support L. Terry, Chief Engineer i
D. Wilken, Staf f Assistant
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1.2 NRC Personnel
- Denotes personnel that attended the exit meeting.
In addition to the
personnel listed above, the inspectors contacted other personnel during this l
inspection period.
t 2 EXIT MEETING
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An exit meeting was conducted on April 19, 1993. During this meeting, the
.i inspectors reviewed the scope and findings of the report.
The licensee did
not identify as proprietary any information provided to, or reviewed by, the
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inspectors.
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