IR 05000458/1987028
| ML20237A835 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 12/01/1987 |
| From: | Chamberlain D, William Jones, Madsen G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20237A811 | List: |
| References | |
| 50-458-87-28, NUDOCS 8712150298 | |
| Download: ML20237A835 (16) | |
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APPENDIX B l
U. S. NUCLEAR REGULATORY ColeIISSION
REGION IV
NRC Inspection Report:
50-458/87-28 Docket:
50-458 i
Licensee: Gulf States Utilities Company (GSU)
P. O. Box 220 St. Francisville, Louisiana 70775 Facility Name:
River Bend Station (PSS)
Inspection At:
River Bend Station, St. Francisville, Louisiana Inspection Conducted: November 1 through November 21, 1987 W
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Inspectors:
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D. D. Chamberlain, Senior Resident Inspector Date Project Section C, Division of Reactor Projects
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W. B. Jones, Resident Ipspector Date Project Section C, Division of Reactor Projects j
Approved:
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ff. ~L. Itadsen, (Acting) Chief, Project Section C Date
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Division of Reactor Projects l
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Inspection Summary Inspection Conducted November 1 through 21, 1987
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(Report 50-458/87-28)
Areas Inspected:
Routine, unannounced inspection of the licensee identified problem with a misaligned instrument root valve, licensee action on previous inspection findings, surveillance test observation, maintenance observation, safety system walkdown, and operational safety verification.
Results: Within the areas inspected, three. potential violations were identified (failure to maintain required high drywell pressure instruments operable, paragraph 2, failure to follow a temporary test procedure, paragraph 7, and failure to obtain approved cancellation extensions for PMRs, paragraph 7).
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DETAILS
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Persons Contacted l
D. L. Andrews, Director, Nuclear Training l
W. J. Ecck, Supervisor, Reactor Engineering I
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
- J. R. Dunkelberg, Supervisor, Projects R. W. Frayer, Director, Projects P. E. Freehill, " M e Manager A. O. Fredieu, Aa,stant Supervisor, Operations J. D. Gore, Consultant, Cajun f
- P. D. Graham, Assisi. ant Plant Manager, Operations
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- E. R. Grant, Director, Nuclear Licensing J. R. Hamilton, Director, Design Engineering K. C. Hodges, Supervisor, Chemistry
- L. G. Johnson, Site Representative, Cajun G. R. Kimmell, Director, Quality Systems
- R. J. King, Supervisor, Nuclear Licensing A. D. Kowalczuk, Director, Oversight J. H. McQuirter, Licensing Engineer
- T. G. Murphy, Supervisor, Planning and Scheduling V. J. Normand, Supervisor, Administrative Services
- W. H. Odell, Manager, Administration
- T. F. Plunkett, Plant Manager
- M. F. Sankovich, Manager, Engineering R. R. Smith, Engineer, Nuclear Licensing
- R. B. Stafford, Director, Operations (QA)
- K. E. Suhrke, Manager, Project Management
- R. J. Vachon, Senior Compliance Analyst R. G. West, Supervisor, General Maintenance D. W. Williamson, Supervisor, Operations The NRC inspectors also interviewed additional licensee personnel during the inspection period.
- Denotes those persons that attended the exit interview conducted on November 25, 1987. The NRC resident inspector (RI), W. B. Jones also attended the exit interview.
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2.
Misaligned Instrument Root Valve This area of inspection was conducted to review the licensee identified problem with a misaligned instrument root valve. The NRC resident
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inspectors were notified by the licensee on November 17, 1987, that an instrument root valve for high drywell pressure instruments had been found closed during the performance of a nuclear boiler instrumentation system River Bend is presently in the first refueling valve lineup that day.
outage and the licensee was in the process of reverifying valve lineups The valve was for all safety systems when this problem was discovered.
immediately returned to the open position and the licensee initiated an It is investigation to determine the cause of the misaligned valve
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notable that a professional work climate exists at River Bend where problems of this nature are identified by plant personnel and immediately A
brought to management attention and to the attention of the NRC.
condition report program is used to effect corrective action This self-identification of problems is encouraged by investigations.
senior management and the two operators who identified this problem wert.
It is also notable given a letter of commendation by plant management.
that this problem was found because of the licensee's own initiative to As 6 result of the reverify valve lineups during this refueling outage.
licensee's investigation and response to questions by the resident inspectors, the following information was obtained for the identified condition.
Identification and Cause for the Misaligned Valve a.
The licensee identified the misaligned instrument root valva o
during the performance of a valve lineup.
The licensee was reverifying all safety systems valve lineups during this first refueling outage as an internal commitment to establish a high level of confidence with system alignments.
When the misaligned valve was found it was immediately returned o
to the correct open position and licensee management and the NRC resident inspectors were immediately notified.
The licensee initiated corrective action investigation with a condition report.
The licensee is also preparing the required Licensee Event Report (LER) to be submitted to the NRC.
TU licensee found that the initial valve lineup for the nuclear o
boiler instrumentation system performed in August of 1985 had A
not aligned valve IRCS-V122 to the required OPEN position.
comment was documented on the valve lineup sheet that a maintenance work request (MWR) had bee-issued to repair this valve.
MWR 004128 for this repair was done in September of 1985.
The repair work involved installing packing gland studs and nuts and there was no evidence that the valve was It is repositioned before or after this maintenance activity.
believed by the licensee that this valve had been isolated since August of 1985 until it was found closed on November 17, 1987.
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inspectors were notified by the licensee on November 17, 1987, that an instrument root valve for high drywell pressure instruments had been found closed during the performance of a nuclear boiler instrumentation system valve lineup that day.
River Bend is presently in the first refueling outage and the licensee was in the process of reverifying valve lineups for all safety systems when this problem was discovered.
The valve was immediately returned to the open position and the licensee initiated an investigation to determine the cause of the misaligned valve.
It is notable that a professional work climate exists at River Bend where problems of this nature are identified by plant personnel and immediately brought to management attention and to the attention of the NRC.
A condition report program is used to effect corrective action investigations.
This self-identification of problems is encouraged by senior management and the two operators who identified this problem were given a letter of commendation by plant management.
It is also notable that this problem was found because of the licensee's own initiative to reverify valve lineups during this refueling outage.
As a result of the licensee's investigation and response to questions by the resident inspectors, the following information was obtained for the identified condition:
a.
Identification and Cause for the Misaligned Valve o
The licensee identified the misaligned instrument root valve during the performance of a valve lineup.
The licensee was reverifying all safety systems valve li.eups during this first refueling outage as an internal commitment to establish a high level of confidence with system alignments.
o When the misaligned valve was found it was immediately returned to the correct open position and licensee management and the NRC resident inspectors were immediately notified.
The licensee initiated corrective action investigation with a condition j
report.
The licensee is also preparing the required Licensee Event Report (LER) to be submitted to the NRC.
o The. licensee found that the initial valve lineup for the nuclear boiler instrumentation system performed in August of 1985 had not aligned valve IRCS-V122 to the required OPEN position.
A comment was documented on the valve lineup sheet that a maintenance work request (MWR) had been issued to repair this valve.
MWR 004128 for this repair was done in September of 1985.
The repair work involved installing packing gland studs and nuts and there was no evidence that the valve was repositioned before or after this maintenance activity.
It is believed by the licensee that this valve had been isolateo since August of 1985 until it was found closed on November 17, 198 _ -.
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o The shift supervisor and the operators performing the initial.
valve lineup signed and dated the valve lineup with only the i
comment on the checklist.
No other documentation was provided to disposition the misaligned valve.
o Procedure ADM-0022, " Conduct of Operations" which was in place during 1985 requ4ed that when all check list items were completed, the operator who completed the final item, signed and dated the check list signifying completion.
For safety-related and other important systems an independent position verification -
would then be performed by a second qualified individual.
Each completed check list was then reviewed by the shift supervisor I
to verify completion and to determine exceptions or unusual conditions.
The same basic procedural requirements for system lineup check lists apply today.
The licensee believes an error was made in signing this valve lineup as completed without assuring disposition for valve 1RCS-V122 not being aligned to the proper OPEN position.
o The subsequent maintenance work performed on the valve did not reposition the valve because it was not necessary to change the valve position to perform the maintenance.
o It is not clear from the documentation available whether the operators and shift supervisor just failed to note the comment on the check list or whether it was believed that the maintenance work performed would realign the valve to the correct OPEN position.
o Quality assurance (QA) audits and surveillance of system lineups have been performed but this problem was not detected on a sampling basis.
The operations QA group performs system lineup walkdowns but they do not normally look at instrumentation only systems because of the difficulty in determining valve position for small instrument root valves with a visual inspection only.
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o No management review of system lineups other than the shift supervisor is required by licensee programs; therefore, management would not necessarily become aware of a problem of this nature, o
Management did initiate action to reverify all safety system valve lineups during this refueling outage to provide an extra measure of confidence with system alignments.
o No other opportunities occurred to identify this misaligned valve until the system lineup was reperformed during this outage.
The surveillance tests performed for channel checks and functional calibrations would not uncover a problem of this
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natun because of the instruments reading zero under normal conditions and calibrations do not input a pressure signal from inside the drywell.
b.
Potential Violation / Safety Significance
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o The instrument root valve IRCS-V122 isolates the drywell pressure sensing line which feeds three pressure transmitters (1821-PT-N067G, 1821-PT-N067C, and IC71-PT-N0500).
o Pressure transmitters N067G and N067C supply electronic trip units N667G and N667C for initiation logic.of the high pressure core spray (HPCS) system.
The logic system contains four channels in a single trip system arranged in a one out of two taken twice logic to energize and initiate the HPCS system on high drywell pressure.
o River Bend Technical Specifications (TS) Section 3.3.3 requires all four channels of DRYWELL PRESSURE-HIGH for the HPCS system to be operable in OPERATIONAL CONDITIONS 1, 2, and 3.
o With the instrument root valve closed, two of the four channels required by TS, would have been inoperable.
With these two channels inoperable, the required TS ACTION is to declare the HPCS system inoperable, o
The remaining pressure transmitter N050C supplies electronic trip unit N650C for initiation logic of a reactor SCRAM.
This reactor protection system (RPS) logic contains two channels per two trip systems arranged in a one out of two taken twice logic to deenergize and initiate a reactor SCRAM on high drywell pressure.
o Piver Bend Technical Specification Section 3.3.1 requires two channels of DRYWELL PRESSURE-HIGH reactor SCRAM initiation for each of two trip systems to be operable in OPERATIONAL CONDITION 1 and 2.
o With the instrument root valve closed, one of the two channels required by TSs for one trip system would have been inoperable.
With this one channel inoperable, the required TS ACTION is to place the inoperable channel and/or t. hat trip system in the tripped condition within 'l hour.
o The licensee investigated maintenance and surveillance activities for the redundant channels of high drywell pressure SCRAM initiation and HPCS system initiation, that occurred during the time frame of August 1985 to November 1987.
No maintenance activities were performed on redundant channels during the OPERATIONAL CONDITIONS required for operability.
Monthly surveillance functional tests were performed which'would
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1 have caused the high drywell pressure HPCS system initiation function to be out of service twice during each month for an l
average of 20 minutes each time.
The monthly surveillance l
functional tests would have also caused the high drywell pressure reactor SCRAM initiation to be out of service once each month for an average of 20 minutes each time.
It is noted'that the plant was in an operational condition where these
initiations were required to be operable for the majority of l
each month from January 1986 to September 1987 excluding October
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and November of 1986 (maintenance and surveillance outage).
The failure to maintain four channels of DRYWELL PRESSURE-HIGH for the HPCS system initiation and two channels per trip system of DRYWELL PRESSURE-HIGH for reactor SCRAM initiation operable as required by TS Sections 3.3.3 and 3.3.1 or to take the required TS ACTION for inoperable channels was identified by the SRI as a potential violation.
(458/8728-01) This potential violation would have prevented the HPCS system from performing the intended safety function of initiating and injecting water to the reactor vessel from a high drywell pressure signal under certain conditions and would have prevented the intended safety function of a reactor SCRAM from a high drywell pressure signal under certain conditions.
The condition where these intended safety functions would have been prevented was during required surveillance testing of redundant channels for a short time each month.
It is noted that the HPCS system initiations from low reactor water level and manual initiation and all of the other reactor SCRAM initiations including manual SCRAM were not affected by this potential violation.
Also, several alarms and indications that exist in the control room to alert the operator of l
high drywell pressure conditions were not affected by this potential
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violation.
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Similar Occurrences Two occurrences of misaligned instrument valves have previously been identified by the licensee on August 11 and September 14, 1987, respectively.
These occurrences were documented in Licensee Event Report 87-017 and were also identified as an unresolved item in NRC Inspection Report 50-458/87-20.
These occurrences did not prevent a safety system from performing the intended safety function under any conditions.
These valves were contained on instrument valve lineups which are performed by instrument and control (I&C) personnel.
I&C personnel also manipulate these types of valves during maintenance and surveillance.
This does not include instrument root valves of
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the type identified durir,g the latest problem identification which
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are operated and controlled only by operations personnel.
It was believed for these previous occurrences that the valves were probably l
left. misaligned during a maintenance or surveillance activity because
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of the methods used by I&C personnel to verify valve position.
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Corrective actions for these previous occurrences included procedures I
changes to ensure a positive method of verifying the as-left valve i
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position and a redefining of the role of the independent I&C verifier.
Additional training for I&C technicians was also provided.
Instrument valve lineups for several systems were reperformed and a commitment was made to reverify all safety system instrument valve lineups during the refueling outage, d.
Licensee Review of Existing Program Controls / Planned Corrective Actions o
The licensee review of existing program controls versus. program controls in place at the time of the potential violation indicates some strengthened program control was implemented right after this problem occurred.
This involves the use of tracking limiting condition for operation (LCO) sheets.
Tracking LCOs are initiated when maintenance work is initiated or when valve clearances are issued on systems that are not required to be operable for the current operational condition of the plant, These tracking LCOs must be dispositioned prior to entering the operational condition for which the system is required.
A tracking LC0 would have been the method for documenting and assuring disposition of the misaligned valve and the subsequent maintenance activity on the valve.
The licensee has evidence that this tracking LC0 system was used by the same shift supervisor at a later date to track similar activities, o
The licensee has modified Procedure ADM-0022, " Conduct of Operations" to clarify the intent that the shift supervisor will resolve any discrepancies noted prior to final sign-off of the valve lineup check list.
o The licensee will complete their planned reverification of all safety system lineup during this refueling outage and they have committed to reverify safety system lineups during all future refueling outages.
o The licensee has committed to an independent management review of safety system valve lineup check lists to assure that all discrepancies are properly resolved.
This management review is l
in addition to the required shift supervisor. review.
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The licensee has assembled a list of all safety-related instruments which normally indicate zero during operations and for which the surveillance channel check would not reveal a-misaligned valve.
The licensee is reviewing surveillance test methods and potential additional controls that could be
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implemented for these instruments.
This could include more frequent valve alignment verification and/or locking valves in the proper position.
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o The licensee is reviewing the QA surveillance program to determine if changes are needed to prevent th;s type of problem from going undetected for over 2 years.
The licensee will document their investigation of this problem and planned corrective actions in a Licensee Event Report to be submitted no later than December 17, 1987.
The resident inspectors will monitor the completion of licensee committed actions prior to plant restart from this first refueling outage.
3.
Licensee Action on Previous Inspection Findings a.
(Closed) Violation (458/8627-02):
Failure to Follow Surveillance Test Package During Performance of Division III Weekly Battery Surveillance Test - The licensee has revised the weekly surveillance procedures for the Division I, II, and III batteries, to require that a second individual verify that the cells with the lowest specific gravities are utilized as the pilot cells. 'The Electrical Maintenance Supervisor is maintaining the results of the latest Quarterly Battery Test on file for determining which battery cells shall be utilized as the pilot cells.
A temporary change notice.has been initiated for the diesel fire pump battery weekly surveillance to also require independent verifications of the pilot cells utilized during the surveillance.
This violation is closed.
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(Closed) Open Item (458/8639-03):
Incorporation of Comments into Surveillance Procedures - The licensee has designated six individuals l
to review procedures for applicable comments and to incorporate these comments into the procedures during their next revision.
A preliminary change notice (PCN) has also been developed for use with the station surveillance program which allows for changes to be made to a procedure in the field provided that:
o The intent cf the procedure is not changed; o
The PCN is approved by two members of plant management, one of whom must be knowledgeable of the activities required by the procedure and the other is the on-shift shift supervisor or control operating foreman; and o
None of the questions relating to 10 CFR 50.59 are marked "yes."
Following completion of the surveillance test, the PCN is processed as a temporary change notice.
This open item is closed.
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Surveillance Test Observation During this inspection period, the NRC resident inspectors observed the i
performance of Surveillance Test Procedure STP-309-0601, " Division I j
18-month ECCS Test," on November 9-11, 1987.
This surveillance test was performed to verify that the Division I diesel generator (D/G) and associated low pressure core spray (LPCS) and low pressure coolant injection (LPCI)
'A' systems met the following 18-month surveillance requirements:
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The emergency busses deenergize and load shed on a loss of offsite power (LOP) in conjunction with an emergency core cooling system (ECCS) signal; o
The diesel generator auto starts and energizes the busses with permanently connected loads within 10 seconds; o
Each automatic isolation valve actuates to its isolation position; o
The automatic load timers sequence the loads onto the bus within plus or minus ten percent of the design interval; o
The LPCS and LPCI 'A' pumps activate and each automatic valve in the flow path actuates to its correct position; o
Division I trip systems activate when required; o
The ECCS response time is within the limits established in TS Table 3.3.3.-3; o
The containment unit coolers activate as required; o
A simulated ECCS signal with the D/G operating in the test mode and connected to the bus overrides the test mode and returns the D/G to standby operation; o
The ECCS signal automatically energizes the emergency loads with offsite power; o
The D/G does not trip on a full load reject; o
The D/G starts on a loss of coolant accident signal but does not tie onto the bus; o
During an ECCS signal all D/G trips are bypassed except engine overspeed and generator differential current; and o
The D/G can operate for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at loads between 3030-3130 kw without tripping.
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During the performance of the test, no conditions were discovered which would have prevented the Division I ECCS from performing its intended function.
One test exception remains to be closed involvin an isolation signaltotheRHRupperfuelpoolcoolingassistvalve1E12gMOVF037A.
During a subsequent inspection, the NRC inspectors will review the l
completed test data package to verify that all the TS requirements were met.
No violations or deviations were identified in this area of the inspection.
5.
Maintenance Observation During this inspection period, the resident inspector observed maintenance activities conducted under Prompt Maintenance Work Order (PMW0) 55733.
This PMWO was initiated on November 9,1987, to repair the Division II 125 VDC battery supply breaker, 1ENB*ACB581.
The resident inspector verified through observation and review of records that:
o The activities did not violate limiting condition for operation (LCOs);
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o The required administration approvals and tag-outs were obtained before initiating work; o
The procedures used were adequate to control the work; o
The equipment was tested before being returned to service; and o
Adequate quality control coverage was provided as required for work performed under PMW0s.
No violations or deviations were identified in this inspection area.
6.
Safety System Walkdown On November 17, 1987, the NRC resident inspectors performed a walkdown of the low pressure core spray (LPCS) system with the unit in mode 4.
The LPCS system along with the high pressure core spray system were established to meet the emergency core cooling system (ECCS) operability requirement for mode 4.
The resident inspectors observed that:
o All valves were properly aligned and locked as required by Station Operating Procedure 50P-0032, " Low Pressure Core Spray," (Manual isolation valve 1E21*F007 was observed to be open by control room indications.
All ECCS manual isolation valves will be observed to ensure all valves are locked open by a NRC inspector prior to final closeout of the drywell);
o The Division I' keep fill system was operating as required;
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o No abnormal control room instrumentation readings or alarms were present;
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o No leakage from major components was present; o
The LPCS upper and lower bearing oil reservoirs were properly filled; and o
Accessible hangers and supports were intact.
During the review of control room instrumentation, the resident inspectors noted that the air actuated arm of the testable check valve IE21*A0VF006 l
indicated mid position on the control board.
The lever actuating arm had
been removed during local leak rate testing (LLRT) to facilitate proper i
seating of the valve disc.
The upper jam nut, flanged nut and lever arm were preventing the disc from seating properly.
The lever arm was removed by a maintenance work order during LLRT.
Modification request (MR) 87-0780 has been initiated to permanently remove the lever arms from the following valves IE21*A0VF006, 1E12*A0VF0418, 1E51*A0VF065, and 1E51*A0VF066 because they will not seat properly.
The licensee presently only tests these valves during cold shutdown as required by their inservice inspection (ISI)
program.
The valves can still be tested manually with the lever arm to meet the ISI requirements.
Actual valve disc position is still indicated in the control room at all times.
The NRC inspectors are monitoring licensee actions for revision of existing procedures to indicate this design change and training the reactor operators on the modification.
No violations or deviations were identified in this area of the inspection.
7.
Operational Safety Verification The resi?- * inspr S rs continue to monitor control room activities and conduct o wing the refueling outage.
Control room activities and conduct were generally observed to be well controlled.
Proper control room staffing was maintained, and access to the control room operational areas was controlled.
Operators were questioned regarding lit annunciators, and they understood why the annunciators were lit in all cases.
Selected shift turnover meetings were observed, and it was found that information concerning plant status was being covered in each of these meetings.
A walkdown of the low pressure core. spray (LPCS) system was conducted, and the results are documented in paragraph 6 of this report.
Plant tours were conducted and several areas were noted which will require extensive cleaning prior to restart following the outage.
The licensee has been identifying areas needing cleaning on a housekeeping list during this outage.
In recognition of a need for aggressive action to assure that required cleaning is completed, the plant manager has assigned area coordinators to monitor this effort.
The resident inspectors will continue to monitor licensee actions in this area as the outage is completed.
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General radiation protection practices were observed and no' problems were noted.
Personnel exiting the radiation control area (RCA) were observed and radiation monitors were being properly utilized to check for contamination.
The resident inspectors observed security activities in the central alt.rm station, secondary alarm station and in the plant and it was noted that alarms were being responded to as required.
Plant perimeter walkdowns were conducted, and no problems were noted.
Personnel entry and exit from the protected area were observed, and no problems were noted.
The resident inspectors also monitored the reactor pressure vessel (RPV)
hydro, reviewed the ultimate heat sink heat rejection capacity preliminary test results, reviewed the status of prompt modification requests (PMRs),
and reviewed licensee actions on operational events and potential problems.
The results of reviews of selected items are described below:
a.
RPV Hydro On November 19-20, 1987, the licensee performed temporary procedure (TP) 87-25, "RPV Inservice Leakage Test," for the inservice leakage test on the reactor presrare vessel (RPV) and associated piping as required by ASME Code XI.
During the performance of this test, the NRC resident inspectors noted that:
o The reactor coolant was maintained below 200 F; o
RPV metal temperature was maintained greater than 135 F; o
RPV pressure was maintained at 1025 psig plus or minus 15 psig; o
Two emergency core cooling systems were available at all times; o
No leakage was identified within the pressure boundary with the exception of valve packing and the mechanical seals; o
Maintenance work order requests were generated to repair the leaks that were identified; and o
Control rod scram timing test was performed with RPV pressure i
greater than 950 psig.
Prior to beginning the RFV pressurization the shift supervisor (SS)
conducted a test briefing in the control room with the reactor operators that were to perforin the test, and other personnel assigned to monitor the test.
The SS requested that all personnel not associated with the test to leave the control area and the control room was posted, restricting access to only those individuals associated with the RPV hydro test.
When the test briefing was initiated, individuals that had been performing surveillance tests interrupted the briefing and requested the assistance of the reactor
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operators.
This occurred several times at the onset of the test briefing despite requests by the SS for the individuals to continue their surveillance tests at a later time.
These interruptions resulted in a disjointed test briefing and a distraction for the operators at the beginning of the RPV hydro.
When the vessel head vents were closed in preparation for the RPV hydro, the resident inspector noted that the residual heat removal (RHR) vessel suction valves 1E12*MOVF009 and 1E12*MOVF008 had not been closed although step 7.7.4 of the TP which had been signed off as complete required this to be performed, along with shutting down the RHR pump and isolating 1E12*MOVF053A and 1E12*M0VF0538.
The SS was notified of the misaligned valves, and they were immediately closed.
This failure to perform all the required actions of the above step prior to initialing the step as complete was identified by the RI as a potential violation (458/8728-02)..Had the valves been left open during the hydro, an over pressurization of the RHR system would not have occurred.
This is because the 1E12*MOVF008 and 1E12^MOVF009 valves receive an isolation signal at 135 psil, alarms annunicate at 180 psig and relief valves are provided on the suction to the RHR system which would lift at approximately 200 psig.
Several factors appear to have contributed to the above apparent violation.
Them factors include:
Distractions for the operating crew during the test briefing; o
Multiple actions required by a single step, particularly with o
plant conditions established such that not all actions in the step are performed at the same time; and o
The operators are not trained on the TP prior to the time the procedure is performed.
No other problems were noted with test performance and the test was completed on November 20, 1987.
b.
Ultimate Heat Sink Test On October 29 and 30, 1987, the licensee conducted a thermal performance test on the standby cooling tower.
The instrumenting, data collection and evaluation of the test results was performed by Environmental System Corporation.
The test was conducted utilizing a secondary heat source and cells 1 and 4 of the standby cooling tower.
Two code tests were performed on the towers.
The first was performed with a wet bulb temperature of 53.3 F and the second with a wet bulb temperature of 60.1 F.
The results of these tests were compared with the performance curves supplied by the tower manufacturer.
It was found that the results closely matched the performance curves and
that an extrapolation of data for a 66 F wet bulb temperature as
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recommended by ASME PTC 23 was possible.
An independent review of the test results was performed by a Stone and Webster Engineering Corporation cooling system specialist who also served as a member and I
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vice chairman of the ASME PTC 23 committee.
No test results were identified that would indicate the standby cooling tower would not perform as described in the updated Safety Analysis Report.
No violations or deviations were identified in this area o' 9e inspection.
c.
Status of Prompt Modification Requests (PMRs)
On November 17, 1987, the resident inspectors reviewed the control room PMR status log and it was noted that 16 PMRs had exceeded the anticipated date for cancellation.
A review of these PMRs revealed that memorandums had not been approved and forwarded to document control to establish new cancellation dates.
Examples of this include:
o PMR 86-98 Cancellation Due September 15, 1987 o
PMR 86-128 Cancellation Due October 7, 1987 o
PMR 87-35 Cancellation Due October 23, 1987 Procedure ENG-3-006, " River Bend Station Design and Modification Request Control Plan," requires that the anticipated cancellation date be recorded in block 23 of a PMR.
If the PMR cannot be
cancelled (converted to a modification request or system returned to original configuration) by the date indicated in block 23, a memorandum explaining the need for an extension and the new cancellation date must be prepared, approved and forwarded to-document control for permanent retention.
The failure to obtain approved cancellation extensions for the above noted PMRs was identified by the SRI as a potential violation.
(458/8728-03)
d.
Emergency Diesel Generator Winding This area of inspection was conducted to provide continuing followup on the previously identified problem with an emergency diesel
generator rotor pole winding.
This problem was identified by the licensee on October 27, 1987, and involved a problem with one rotor pole on the Division II diesel generator where the outer winding wrap had delaminated and bowed out toward the stator.
This was found during a scheduled refueling outage inspection of the generator.
The rotor pole winding was removed and repaired and a failure analysis
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was conducted.
The initial results indicate a lack of adhesion from the polyester resin used between the winding wraps.
The most
probable causes of this lack of adhesion is inadequate attention to shelf life and/or storage conditions of the resin prior to or during
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the manufacture of the generator.
The polyester resin is a Sterling Company of Pennsylvania product (S-D111A) and it has a 3-month shelf
life when stored at 40 F.
The product was apparently discontinued in j
1984.
The licensee is working with the generator manufacturer
(Electric Products) to attempt to determine time frame of and conditions during the manufacture of the River Bend generators.
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licensee also is establishing a plan for electrical tests and video tape magnified visual ins.oections to be conducted during this outage to establish baseline data for future surveillance inspections of both generators at River Bend.
The licensee is also investigating the feasibility of installing mechanical braces between rotor pole windings to prevent winding distortions.
The resident inspectors will continue to monitor licensee actions on this problem.
8.
Exit Interview An exit interview was conducted with licensee representatives (identified in paragraph 1).
During this interview, the SRI reviewed the scope and findings of the inspection.
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