IR 05000458/1989028
| ML20247R297 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 07/27/1989 |
| From: | Constable G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20247R268 | List: |
| References | |
| 50-458-89-28, NUDOCS 8908070422 | |
| Download: ML20247R297 (14) | |
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APPENDIX B
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report: 50-458/89-28 Operating License:
NPF-47 Docket: 50-458 Licensee:. Gulf States Utilities Company (GSU)
P.O. Box 220 o
St. Francisville, Louisiana 70775 Facility Name:
River Bend Station (RBS)
Inspection At:
RBS, St. Francisville, Louisiana Inspection Conducted: June 1-30, 1989 Inspectors:
E. J. Ford, Senior Resident Inspector W. B Jones, Resident Inspector Approved:
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/M 87hf G. L. Constable, Chief, Project Section C Date Division of Reactor Projects Inspection Summary Inspection Conducted June 1-30, 1989 (Report 50-458/89-2,81 Are s Inspected:
Routine, unannounced inspection of plant events, operational safe'ty verification, maintenance and surveillance test observation, and licensee action on a previous inspection finding.
Results: On June 17, 1989, two valves were identified by the licensee as being liiTs'aTTined (paragraph 3.c). The first valve became misaligned following an inadequate valve lineup after flushing and venting activities on the control rod drivF mechanisms. The second event involved a pressure transmitter on the Division I penetration valve leakage control system. The licensee's extensive corrective actions following the fh st event identified the second misaligned valre. Corrective actions are being taken to prevent recurrence.
During modifications of the instrument air system, the licensee deviated from
'the procedural requirements of the modification control program (paragraph 5).
Work activities were allowed to proceed which deviated from the latest revision
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,I to the modification request. This activity was performed under the cognizance i
of both the quality assurance and engineering organizations.
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- Operations personnel performed their duties in' an exemplary manner during this inspection period. -Several challenges were made of ttw operators knowledge of <
f; plant: systems and procedures.
In each case,Lthe operators performed as
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expected and several of their conservative actions mitigated possible plant V.
. transients.
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DETAILS 1.
Persons Contacted J. E. Booker, Manager, Oversight E. M. Cargill, Supervisor, Radiation Programs J. W. Cook, Lead Environmental Analyst, Nuclear Licensing
- T. C. Crouse, Manager, Quality Assurance (QA)
- J. C. Deddens, Senior Vice President, River Bend Nuclear Group D. R.'Derbonne, Assistant Plant Manager, Maintenance
- L. A. England, Director, Nuclear Licensing A. O. Fredieu, Supervisor, Operations P. E. Freehill, Outage Manager J. D. Gore, Cajun Consultant
- P. D. Graham, Special Assistant, Senior Vice President
- J. R. Hamilton, Director, Design Engineering
- G. K. Henry, Director, Quality Assurance Operations D. E. Jernigan, General Maintenance Supervisor G. R. Kimmell, Director, Quality Services R. J. King, Supervisor, Nuclear Licensing
- W. H. Odell, Manager, Administration
- T. F. Plunkett, Plant Manager
- M. F. Sankovich, Manager, Engineering
- J. P. Schippert, Assistant Plant Manager, Operations and Radwaste J. Venable, Assistant Operations Supervisor
- R. G. West, Assistar.t Plant Manager, Technical Services The inspectors also interviewed additional licensee personnel during the inspection period.
- Denotes those persons that attended the exit interview conducted on July 12, 1989.
2.
Plant Status On June 13, 1989, the licensee experienced two events which resulted in a partial loss of offsite power.
In the first event, the Division II emergency diesel generator started and closed onto the safety-related bus as required, which was the condition when the second event occurred.
During both events, the safety-related systems responded as expected.
On June 23, 1989, the licensee com.leted their outage when the main generator was synchronized to the grid. The outage consisted of an 85-day refueling outage which ended on June 8,1989, and was inrediately followed by a 16-day forced outage. The forced outage resulted when a preferred station transfonner developed a fault and required replacement.
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On June 29, 1989, a leak developed on the electrohydraulic control system which required the licensee to remove the main generator from the grid and subsequently manually shutdown the reactor.
3.
Followup of Events (93702)
During this inspection period, the inspectors reviewed licensee condition
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reports (CRs) and 10 CFR 50.72 reports and held discussions with various olant personnel to ascertain the sequence, cause, and corrective actions taken on selected events. A discussion of these selected events is given below:
a.
Preferred "B" Station Transformer
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On May 29, 1989, the Preferred "B" station transformer failed when the operators attempted to energize the transformer. The transformer, which supplies nonsafety-related loads, had been out of service since April 19, 1989. A modification was made to the transformer while it was out of service to provide wildlife protection boots for the transformer terminals. This modification did not result in the subsequent transformer failure.
Prior to the licensee energizing the transformer on May 29, 1989, the shift supervisor directed that the transformer be unloaded and that all personnel stay clear of the transformer yard. When the Preferred
"B" station transformer was energized, a 230,000evolt upstream breaker tripped and the transformer oil ignited. The fire was suppressed by the normal fire suppression system, with no offsite assistance required. No personnel injury or equipment damage resulted from the event. This was largely because of the protective actions taken prior to energizing the transformer.
The replacement transformer was energized on June 20, 1989. The transformer, now designated as Preferred "F" station transformer, was subsequently tested and returned to service on June 22, 1989.
Prior to completion of the refueling outage, the licensee evaluated the impact of nperating with Preferred "F" station transformer out of probability from 10 ption ingicated an increase in core melt service. This evalu to 10'.
Based on this analysis, the licensee elected not to synchronize the main generator to the grid until the transformer was back in service. This resulted in the subsequent forced outage June 8-23, 1989.
No violations or deviations were identified in this area of the inspection.
b.
Partial Loss of Offsite Power On June 13, 1989, the licensee experienced two events which resulted in a partial loss of offsite power.
In the first event, the i
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Division II emergency diesel generator started and closed onto the
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I safety-related bus as required. During both events, the safety-related systems responded as expected.
The first event involved work on the Preferred "F" station
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l transformer (IRTX-XSRIF).
Contract personnel were performing wire terminations on the IRTX-XSRIF when a sudden pressure trip occurred on IRTX-X5 RID. The licensee's investigation of the event revealed that the lead the contractor had cut to replace the lug was the sudden pressure trip for both 1RTX-XSRID and 1RTX-XSR1F.
Review of the associated print indicated the lead provided only a sudden pressure alarm. However, the lifted lead tag on the cable did identify the lifted lead as the pressure trip. The print was later detennined to be in error.
While troubleshooting the sudden pressure on 1RTX-XSRID, a relay technician operated a pilot wire relay switch at the Fancy Point Substation. This caused the main generator output breakers to open.
At the time, the licensee was backfeeding nonsafety-related loads through these breakers. This was required because the preferred transformers which supply these loads were out of service. The licensee was able to close the breakers within 10 minutes.
During the second event, a relay technician crew had been sent to the substation to monitor an:1 reset relay targets as needed for sudden pressure trip testing. During this exercise, a relay technician observed an alarm on the main generator pilot wire that had not reset. Although this alarm was outside the scope of the authorized work activity, the technician removed the relay cover and moved the switch off the alarm contact. The switch, however, was moved too far and caused the trip.
On June 1, 1989, the responsibility for maintaining equipment at the substation which directly affects RBS was transferred to the licensee's maintenance program. At the time of the event, equipment under the licensee's control had not been labeled as such. Personnel training on the equipment which had been transferred had not been performed.
The inspectors are continuing to followup on this event.
Further review of this event is required to fully ascertain the procedural controls that were in place when the above two events occurred and to evaluate the corrective actions that have been and will be taken.
The additional review of this event will be documented in the NRC Inspection Report 50-458/89-31.
c.
Licensee Identified Misalianed Valves On June 16, 1989, the licensee entered Operational Condition 2
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(startup) for the first time following the beginning of the refueling outage on March 15, 1989. The subsequent reactor startup was
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observed to be well controlled. Neutron monitoring instrumentation l
was closely monitored during the withdrawal of control rods to ensure
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a short period at criticality did not occur. At approximately 3 2.m.
on June 17, 1989, Control Rod 48-21 was selected for withdrawal to Position 02. Source range monitor response indicated that criticality would likely occur on withdrawal of this control rod.
However, attempts to withdraw the rod were unsuccessful. The most likely cause that the control rod would not withdraw was air entrapment in the control rod (CRD) mechanism. The licensee initiated actions to vent the CRD at its respective hydraulic control unit (HCU). When tne reactor operator arrived at the HCU, he identified that the CRD cooling water riser isolation
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valve (HCU4821-V104)wasclosed. Tha valve is required by the Station Operating Procedure 50P-0002, " Control Rod Drive Hydraulics,"
to be open. This valve being closed did not prevent the control rod from withdrawing and would not have prevented the control rod from scramming if it had been withdrawn. The licensee then performed a walkdown of the remaining HCOs and identified that 18 HCOs did not have the standard operating procedure (S0P) required lock wires on the scram discharge volume isolation valve, inlet riser isolation valve, and withdraw riser isolation valve. All these valves were open as required by the S0P. Based on this finding, the licensee returned to Operational Condition 4.
The licensee's investigation of this incident identified that the valve lineup for SOP-0002 did not contain all the required signatures. This lineup sheet had been completed on May 22, 1989.
The signature omissions appear to have resulted from the manner in which the lineup sheet was set up and not because the verification was not performed. The omissions occurred in the header signature blocks for the applicable HCUs. The affected blocks each had a "1st" or "2nd" typed in block indicating where the first and second verifier should sign in each row.
A review of maintenance activities performed on the HCUs identified thatmaintenanceworkorder(MWO)R126315 called for flushing and venting the CRDs with the missing lock wires. It also called for venting the CRD with the misaligned valve. This MWO was completed on June 2, 1989. Review of the liWO revealed the flushing operation was performed by maintenance and operations personnel. The step in the procedure which would have required verifying valve positions was not applicable. No subsequent lineup verification was performed on the HCUs following completion of the MW0. The failure to perform the final verification was not identified during closecut of the MWO package. The failure to require specific system restoration is an apparent violation (458/8928-01).
To prevent recurrence, the licensee has revised 50P-0002, to make flushing CRDs a procedure with individual signoffs for each step.
l Each valve on the HCUs is now identified on the lineup sheet
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requiring both a first and second verification signature.
Administrative Procedure ADM-0028, " Maintenance Work Order," has been
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revised to require any valve manipulation specified in the job plan to be restored with specific restoration steps.
This requirement will be specifically stated in the MWO package by the job planner.
Maintenance and operations personnel will be trained on this event.
Because of the problem identified with the CRD HCU valve misalignment and the missing seal wires, the licensee performed a 100 percent verification of all safety-related valves in the plant. This effort involved a verification of approximately 11,700. valves.
During this verification, the licensee identified that the drywell pressure transmitter process root valve (LSV*PT21A-V1) was closed.
This valve is required to be open by 50P-0041, " Penetration Valve Leakage-Control System." With this valve closed, the pressure transmitter was rendered inoperable.
This also rendered the Division I penetration valve leakage system (PVLCS) inoperable.
RB Technical Specifications 3.6.1.10 requires that two independent PVLCS divisions
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be operable in Operational Conditions 1, 2, or 3.
The PVLCS is designed to' prevent the unfiltered release of fission products to the environment after a loss of coolant accident (LOCA)
through process lines that penetrate the containment building.
This is accomplished by injecting air between the double discs of each containment isolation valve.
The Division I PVLCS coals the outboard isolation valves, while Division II seals the inboard isolation valves.
The main steam isolation valves (MSIVs) are sealed by the MSIV positive leakage control system (MSIV-PLCS) which utilizes the PVLCS air supply.
MSIV-PLCS operability was not affected by LSV*PT21A-V1 being closed.
The PVLCS can be manually initiated 20 minutes following a LOCA.
Process line pressure must be.below 40 psig before the associated PVLCS isolation valves will open.
Once the PVLCS has been initiated, the process line pressure must be maintained 5 psi greater than than the drywell pressure.
If this condition is not met 100 seconds after initiation, the associated PVLCS isolation valve will close.
This feature of the the PVLCS was rendered inoperable with LSV*PT21A-V1 out of.servic'e.
The measured pressure differential would have been the process line pressure, A backup PVLCS isolation is provided to
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ensure that the MSIV-PLCS shared air supply remains available.
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minutes after initiation, if air flow in th PVLCS is greater than 6 scfm or' accumulator pressure decreases below 50 psig, the entire division of PVLCS will isolate.
Review of the 50P-0041 valve lineup sheet indicates that the pressure transmitter was properly aligned on May 24, 1989.
The containment integrated leak rate test (CILRT) was performed following completion of the valve lineup.
There are four valves associated with the pressure transmitter.
These are the isolation valve (LSV*F64),
isolation root valve (LSV*PT21A-V1), isolation vent valve (LSV*PT21A-V2), and isolation vent valve (LSV*PT21A-V3).
Review of the CILRT test tag log only identifies an LSV*PT21A I
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. isolation valve.and LSV*PT21A vent valve being associated with the
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pressure transmitter. Restoration following the CILRT indicates the two valves were left in the open and closed position, respectively.
The licensee has not been able to establish when the valve, LSV*PT21A-V1, was improperly positioned. However, because the test tag log for the CILRT did not specifically verify the pressure transmitter was properly aligned, the licensee believes the misalignment occurred during restoration from the CILRT. The CILRT procedure is presently being revised to require'a detailed lineup of all valves associated with the CILRT. Specific test tags are being developed for use with the CILRT procedure.
In addition, personnel responsible for performing S0P lineups will now perform the restoration from the CILRT. This corrective action will also be applied to the drywell leak rate test. The licensee has committed to locking open the process root valve on pressure transmitte s that do not provide a remote pressure indication.
The NRC staff has reviewed the licensee's actions involving the above two events. The corrective actions taken which lead to identifying-that LSV*PT21A-V1 was improperly positioned were extensive and i
appropriate. Corrective actions to prevent recurrence are also appropriate. Review of previous corrective actions, in particular those to NRC Violation 458/8728-01, could not have reasonably been expected to prevent the PVLCS problem. During the period the PVLCS was required to be operable, vessel water temperature did not exceed 160 F and vessel pressure remained at atmospheric. Because of the above findings, no violation will issued for the above event in accordance with Appendix C, paragraph V.G.1 of the NRC's " Rules of Practice," Part 2, Title 10, Code of Federal Regulations.
4.
Operational Safety Verification (71707)
The. inspectors observed operational activities throughout the inspection period and closely monitored operational events. Control rr>om conduct and
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activities were generally observed to be well controlled.
Proper control room staffing was maintained and access to the control room was well controlled. Selected shift turnover meetings were observed and it was found that detailed information concerning plant status was being covered.
Several control' beard walkdowns were conducted by the inspectors.
In all cases, the responsible operators.were cognizant as to why an alarm was lit and the reason for each plant configuration. Operational conditions and events, identified through discussions with the reactor operators and review of the shift turnover logs, were identified in the main control room log.
Inoperable. equipment identified during the main control board walkdowns were identified by the applicable limiting condition for operation (LCO).
The inspectors ccnducted several tours of accessible areas of the facility during this inspection period. General housekeeping practices have improved since the completion of the refueling outage. Walkdowns of the
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low pressure core' spray, low pressure coolant injection, and high pressure core spray systems were conducted.
This included verifying that the valves in the drywell were locked open and the associated power supplies for the electrical components were energized.
The inspector observed the reactor startups conducted on June 16 and 19, 1989.
In each case, the startups were well controlled, with gocd
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communications maintained between the at-the-controls (ATC) operator and l
the remaining operating crew.
Following criticality on June 19, 1989, the heatup and power escalation.was handled in a slow and deliberate manner.
Systems which had not been: utilized since operation in March 1989, were closely monitored to ensure that.they performed as expected.
The licensee initiated a manual scram on June 21, 1989, to perform control rod time testing.
Immediately.following the scram, the ATC operator identified that one control rod indicated to be fully ' withdrawn.
The operators entered the applicable abnormal operating procedure and verified that the reactor was suberitical.
Attention was then directed at determining whether the_ control rod had actually inserted.
Approximately 15 minutes later, the control rod indicated full in.
The licenste later determined that a communication problem between the local control position indicating cabinet and the rod action control system had caused the incorrect position indication.
The emergency response information system data taken during the reactor scram showed that the rod had-inserted within the times specified by the Technical Specifications.
. A reactor startup commenced on June 22, 1989, and power escalation continued until June 29, 1989.
Reactor thermal power was at approximately
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99 percent thermal power when an electrohydraulic fluid leak developed on a main turbine stop valve.
The reactor operators immediately began reducing reactor power to allow taking the main turbine off line.
Communications between the ATC operator and operating crew were well maintained and professional.
The shift supervisor (SS) and control operating foreman (C0F) anticipated plant transients and ef fectively coordinated operator activities to minimize the severity of these transients.
Applicable Technical Specifications were adhered to as power was decreased.
After the turbine was taken off line, excessive turbine vibrations were experienced during the subsequent coastdown.
The operators then inserted a manual reactor scrara and broke main condenser vacuum to rapidly decelerate the main turbine.
No problems were experienced with vessel water level or pressure control.
The inspectors verified that selected activities of the licensee's radiological program were implemented in conformance with facility policies, procedures, and regulatory requirements.
Radiation and/or contaminated areas were properly posted and controlled.
Radiation work permits contained appropriate information to ensure that work could be performed in a safe and controlled manner.
During plant tours, the inspectors verified that selected very high radiation area. access doors were locked and closed.
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The ins ectors observed security personnel perform their duties of s
personnel and package search.
Personnel access was observed to be controlled in accordance with established procedures. The inspectors conducted site tours to ensure compensatory posts were proper 13 implemented as required because of equipment failure or degradation.
No violations or deviations were identified in this area of the inspection.
5.
Maintenance Observation (62703)
During this inspection period, the inspector observed a corrective maintenance activity on the Division II standby service water pump discharge valve.
In addition, the MWO packages associated with the installation of the backup air bottles to the control building safety-related instrument air system (IAS) were reviewed.
MWO R056288 was promptly initiated to investigate and repair the lack of valve indication in the main control room for Station Service Water (SSW)
Pump D Discharge Valve SWP*MOV400. On June 20, 1989, the valve position indication for SWP*M0V400 was lost. The licensee entered the appropriate action statement as required by Technical Specification 3.7.1.1 and identified the LC0 as LC0 89-301. With the reactor cperating in Operational Condition 2 (startup), the action statement prevented the licensee from entering Operational Condition 1 (run) and would require a j
shutdown within 30 days if not repaired.
l Prior to releasing the prompt MWO for work, the jcb plan was reviewed by a quality control (QC) inspector to assure that the job plan was adequate to perform the maintenance activity. The QC inspector also observed the j
performance of the maintenance activity as required for a prompt MWO and
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documented the inspection results on QC Inspection Report 89-IR-27080.
The licensee identified a loose connection in the Division II remote shutdown panel which caused the loss of valve position indication. The i
connection was tightened and a postmaintenance test performed on SWP*MOV400. The open and close stroke times, as well as the associated running load amperes, were within the acceptance criteria established in the MWO. The MWO was subsequently reviewed by the control operating foreman, and the associated LC0 was cleared.
Modification Request (MR) 09-0033 was initiated on January 4,1989, to modify the two control building safety-related instrument air accumulators IAS*TK5A and IAS*TK5B by providing each with a backup air bottle. Field change notices (FCN) 1-4 were incorporated into MR 89-0033 and the associated MW0s were initiated to allow the actual design modifications to be made. Subsequent testing of the control building IAS revealed that one additional backup air bottle per IAS tank would not be adequate to meet the air supply requirements.
l The licensee subsequently initiated FCN 5 to install four backup air bottles for each safety-related air accumulator to ensure that the
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safety-related IAS would remain operable following an event involving the loss of the nonsafety re10ted air system. MWO R131476 was initiated to
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fabricate and install the required bottle racks, while MWO R120600 and
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MWO R120599 were initiated to fabricate and install piping and supports as specified by MR 89-0033 FCN 5.
FCN 5 was advanced authorized to begin work on May 25, 1989, as allowed by the licensee's, Procedure ENG-3-006,
" River Bend Station Design and Modification Request Control Plan."
However, MWO R131476 was field work released on May 23, 1989, without the FCN having been approved for work. No field work was performed prior to issuance of the FCN. The remaining MW0s were work released following the advance authorization to begin work on FCN 5.
During the performance of work activities as authorized by the above three MW0s, the licensee was not able to modify the structure in accordance with FCN 5.
Paragraph 6.8.1 of ENG-3-006 precludes maintenance from making changes which alter the end result without using an FCN.
Contrary to this requirement, the licensee issued a memorandum (ED-89-0588) on May 27, 1989, stating that " Engineering will handwrite a numbered memo (89-0033-memo "x") to maintenance with pages(s) attached identifying the change (s)." The licensee subsequently documented 18 changes for field work without reissuing the FCN. These changes included using pipes instead of sockolets, modifying weld configurations, and changing tubing from carbon steel to stainless steel.
The licensee then initiated FCN-7 which incorporated the changes documented by the memorandums. FCN-7 was subsequently issued on June 8, 1989, with Facility Review Committee approval.
During the period that the licensee was deviating from the requirements of ENG-3-006, engineering personnel were closely monitoring activities associated with MR 89-0033.
In addition, QC inspectors' work activities were greatly increased to assure that the as-built structure was adequately documented.
The above practice was discussed with licensee management personnel concerning procedural compliance by all personnel at RBS. Two CRs (CRs89-797 and 89-800) were written to document the procedural noncompliance. A QA engineer subsequently issued CR 89-0820, which independently documented the noncompliance as a QA surveillance finding.
This was done prior to the inspector's review of MR 89-0033. The inspectors spressed their concern that engineering personnel did not comply with all the procedural requirements of ENG-3-006.
In addition, QA management personnel were aware that all the requirements of ENG-3-006 were not being met. Although additional controls were provided, the procedural requirements should have been revised or the procedure adhered to. This procedural compliance was documented as a QA surveillance finding and the practice has not been repeated. This item will be tracked by the NRC staff as inspector follewup item 458/8928-02 pending completion of licensee actions.
(61726)
6.
Surveillance Test Observation _
During this inspection period, the inspectors observed the performance of Surveillance Test Procedures STP-202-0602, " ADS Safety Relief Valve t
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l Operability Test," STP-050-3601, " Shutdown Margin Demonstrations,"
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STP-052-3701, " Control Rod SCRAM Testing," STP-050-3001, " Power Distribution Limits Verification," and STP-207-4242, " Reach Core Isolation Cooling (RCIC) System Isolation, RCIC Equipment Room Differential Temperature High Monthly CHCAL,18-Month LSFT (E51-N603A)," and reviewed the test results for STP-309-0601, " Division I 18-Month ECCS Test." The
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following surveillance activities were observed, and the test results subsequently reviewed.
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STP-202-0602 - This surveillance test procedure was performed on Tune 20,1989, with the reactor in Operational Condition 2 (startup),
to verify operability of each automatic depressurization system (ADS)/ safety-relief valve (SRV). This is accomplished by j
manually opening each ADS /SRV and observing that each valve opens as I
indicated by a change in the main turbine bypass valve position, increased steam flow on the respective main steam line, and actuation of the associated SRV acoustical monitor. An increase in SRV tailpipe temperatures was also nted. The performance of this test satisfies Technical Specifications 4.5.1.e.2, 4.6.4.1, and 4.0.5
. inservice testing requirements and partially satisfies the logic system functional test of Technical Specifications 4.4.2.1.2.b and 4.4.'2.2.1.b for SRV pressure actuation instrumentations.
The inspector observed that each ADS /SRV performed as expected.
Communications between operations personnel were concise, and the activity was well controlled. All the acceptance criteria were met and the STP was properly reviewed and signed off by the control operating foreman.
STP-050-3601 - This surveillance test procedure was performed on
June 19, 1989, to verify that the shutdown margin, as defined in the RBS Technical Specification 3.1.1, is equal to or greater than 0.38 percent delta K/K. The shutdown margin was determined immediately after achieving criticality following the second refueling outage. The licensee calculated the shutdown margin to be i
1.117 percent delta K/K with the highest worth rod withdrawn from the core.
STP-050-3001 - This surveillance test procedure was performed on June 25, 1989, to verify that the average power range monitor (APRM)
flow bias scram and rod block trip setpoints are within the limits of Technical Specification 3.2.2.
Specifically, the procedure requires the adjustment of the APRM gains when the T factor is less than or equal to 1.0 and reactor thermal power is greater than or equal to
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25 percent. The T factor is the ratio of the fraction of rated thermal power (FRTP) divided by the core maximum fraction of limiting
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power density (CMFLPD). The licensee determined that, with the reactor at 34.5 percent thermal power, the T factor was 0.77. The APRM gains were subsequently adjusted to read greater than 45 percent thermal power which met the Technical Specification requirements.
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Thd surveillance requirements of this Technical Specification were tracked utilizing LCO 89-316.
This LCO was subsequently cleared on June 26, 1989, when the T factor exceeded 1.0.
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STP-052-3701 - This surveillance test procedurt was performed on June 20, 1989, to satisfy the postmaintenance test requirements of MWO R102360 for Control Rod 40-37.
Specifically, the maximum insertion times to Notch Positions 13, 29, and 43 were verified by scramming the control rod from the full out position with reactor vessel dome pressure greater than 950 psig. The control rod scrammed within.the times allowed by Technical Specification 3.1.3.2.
Upon withdrawal of,the control rod, the control rod was verified to be
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coupled to the drive mechanism as required by Technical'
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The control rod was subsequently declared operable after successfully completing all the postruaintenance test
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STP-207-4242 - This surveillance test procedure was performed on June 12, 1989, to functionally test the reactor core. isolation cooling (RCIC) equipment area differential temperature high instrumentation (E31N603A) as required by Technical Specification 4.3.2.1, Table 3.3.2-1.5.f.
The inspector observed a portion of the test to verify that proper authorizations were obtained, procedural compliance was observed, and there was adequate communication between the I&C technicians and the reactor operators.
The following surveillance tests were performed in April 1989, and the test results were reviewed during this inspection period.
STP-309-0601 - This surveillance test procedure was performed on April.14-17, 1989, and the observations made during the test are reported in NRC Inspection Report 50-458/89-11.
The licensee has resolved each of the deficiencies identified during the performance of the Division I 18-month emergency core cooling system surveillance test and verified that all the RBS Technical Specification acceptance criteria have been met.
All licensee required reviews have been performed and the test results accepted.
- STP-309-0603 - This surveillance test procedure was performed on April 25-27, 1S89, to verify operability of the Division III emergency core cooling system, including the associated emergency diesel generator.
The observations made during this test are reported in NRC Inspection Report 50-458/89-11.
The licensee has resolved each of the deficiencies identified during the surveillance i
tests, and the applicable Technical Specification acceptance criteria l
have been met.
No violations or deviations were identified.
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7.
Licensee Action on Previous Inspection Findings. (92703)
(Closed) Violation (458/8728-01): Failure to maintain the required minimum channels operable for the high drywell pressure reactor protection system initiation,. primary and secondary isolation, residual heat removal system isolation, and high pressure core spray system initiation.
The licensee has revised General Maintenance Procedure GMP-0042, " Control of Lifted Leads and Jumpers," to require the independent verifier to physically verify that the system has been properly restored. Each maintenance activity that affects operability of a safety-related system is identified on the applicable tracking LC0 form. Prior to closing the LCO,..all ' applicable work documents must be closed by either the shift supervisor or control operating foreman.
In addition, the licensee now requires that all manual valves inside a clearance boundary, that are not J,
- given a specific restoration position by the clearance, are verified by operations personnel to be in the correct position as given in the station operating procedure prior to returning the system to service.
The licensee has committed to performing a 100 percent safety-rel.ited valve lineup prior to startup from each refueling outage. Operations management will review the completed lineups to assure that each noted deficiency has been properly dispositioned. A final review of all safety-related valve lineup sheets will then be periodically performed by the.QA organization.
Following completion of the second refueling outage, the inspector
- reviewed selected safety-related system valve lineup sheets and verified
- that the required reviews have been performed.
- This violation is closed..
8.
Exit Interview An exit interview was conducted with licensee representatives identified
- in paragraph 1 on July 12, 1989.. During this interview, the inspectors reviewed the scope and findings of the report. Other meetings between the inspectors and licensee mana.g ment were held periodically during the e
inspection period to discuss identified concerns. The licensee did not identify as proprietary any information provided to, or reviewed by, the
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' inspectors.
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