ML20197A601
| ML20197A601 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 05/01/1986 |
| From: | Chamberlain D, Farrell R, Jaudon J, William Jones NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20197A586 | List: |
| References | |
| 50-458-86-08, 50-458-86-8, NUDOCS 8605120351 | |
| Download: ML20197A601 (10) | |
See also: IR 05000458/1986008
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APPENDIX B
U. S. NUCLEAR REGULATORY COT!ISSION
REGION IV
NRC Inspection Report: 50-458/86-08
License: NPF-47
Docket: 50-458
Licensee: Gulf States Utilities Company (GSU)
P. O. Box 2951
Beaumont, Texas
77704
Facility Name: River Bend Station (RBS)
Inspection At: River Bend Station, St. Francisville, Louisiana
Inspection Conducted: February 1 through March 15, 1986
Inspectors:
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D. D. Thatiberlain, Senior Resident Inspector
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(pars. 1, 2, 3, 4, 5, 6, 7, 8, and 9)
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W. B. Jones, Resident Inspector
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(pars. 1, 2, 3, 4, 5, 6, 7, 8, and 9)
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( EL F, rell, Senior Resid'ent Inspector
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Approved:
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Inspection Summary
Inspection Conducted February 1 through March 15, 1986 (Report 50-458/86-08)
Areas Inspected: Routine, unannounced inspection of startup test witnessing,
startup test results evaluation, startup test program quality assurance
review, operational safety verification, safety system walkdown, emergency
drill and site tours.
Results: Within the areas inspected, two violations were issued in the areas
of startup test results evaluation and startup test program quality assurance
review, (improper disposition of startup test deficiency and failure of QA
audit program, paragraphs 3 and 4, respectively).
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DETAILS
1.
Persons Contacted
Principal Licensee Employees
- R. E. Bailey, Supervisor, Quality Control (QC)
C. L. Ballard, Projects Supervisor
J. E. Booker, Manager, Engineering, Fuels and Licensing
- W. H. Cahill, Jr. , Senior Vice President, River Bend Nuclear Group
- E. M. Cargill, Supervisor, Radiation Programs
J. V. Conner, Supervisor, Environmental Services
- T. C. Crouse, Manager, Quality Assurance (QA)
- D. L. Davenport, Security Supervisor
- Jan Evans, Stenographer
P. E. Freehill, Superintendent, Startup and Test
A. D. Fredieu, Assistant Operations Supervisor
P. F. Gillespie, Senior Compliance Analyst
- D. R. Gipson, Assistant Plant Manager, Operations
P. D. Graham, Assistant Plant Manager, Services
- E. R. Grant, Supervisor, Nuclear Licensing
- R. W. Helmick, Director, Projects
B. D. Hey, Licensing Engineer
K. C. Hodges, Supervisor, Quality Systems
R. Jackson, Shif t Supervisor, Operations
- R. King, Licensing Engineer
- A. D. Kowalczuk, Assistant Plant Manager, Maintenance
D. N. Lorfing, Senior Nuclear Engineer
- J. H. McQuirter, Licensing Engineer
- W. H. Odell, Manager, Administration
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- T. F. Plunkett, Plant Manager
- S. R. Radebaugh, Assistant Plant Manager, Services
W. J. Reed, Director, Nuclear Licensing
- D. Reynerson, Director, Nuclear Plant Engineering
F. L. Richter, Operations, QA
- R. R. Smith, Licensing Engineer
C. G. Sprangers, Engineer, QA
R. B. Stafford, Director, Quality Services
K. E. Suhrke, Manager, Projects
R. K. Thibodeaux, Acting Assistant Plant Manager-TS
- P. F. Tomlinson, Director, Operations QA
C. W. Walling, QA Engineer
D. Williamson, Operations Supervisor
The NRC senior resident inspector (SRI) and resident inspector (RI) also
interviewed additional licensee, Stone and Webster (S&W), and other
contractor personnel during the inspection period.
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- Denotes those persons that attended the exit interview conducted on
March 20, 1986.
NRC resident inspector, W. B. Jcnes, also attended the
exit interview.
2.
Startup Test Witnessing
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During this inspection period, the SRI and RI witnessed startup testing
conducted under the startup testing program.
The NRC inspectors observed
that: personnel conducting the test were cognizant of the test acceptance
criteria, precautions and prerequisites prior to beginning the test; the
test was being conducted in accordance with an approved procedure and the
test procedure was being used and signed off by the personnel conducting
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the test; and data was being collected and recorded as required.
The NRC
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inspectors witnessed the following startup tests:
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1-ST-28
Remote Shutdown from Outside Control Room
)
1-ST-23A Water Level Setpoint, Manual Feedwater Flow Change
The following observations were made during the performance of the above
startup tests:
a.
Test 1-ST-28, " Remote Shutdown from Outside Control Room"
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The RI observed the performance of startup test 1-ST-28, " Remote
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Shutdown from Outside the Control Room," on February 15, 1986.
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reactor was at approximately 17 percent thermal power when a reactor
scram was initiated from outside the control room by closing the
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inboard main steam isolation valves.
Following the reactor scram,
the reactor operators demonstrated the ability to maintain the
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reactor in a stable hot shutdown condition for greater than
30 minutes, using the remote shutdown panel (RSP).
Although reactor
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pressure never reached the first safety relief valve (SRV) setpoint
and control rod drive (CRD) flow was adequate to maintain. vessel
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level, the licensee was able to demonstrate that reactor pressure and
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water level could be controlled from the RSP by manually cycling open
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one SRV and operating the reactor core isolating cooling (RCIC)
system in the CST to CST mode.
In addition, the suppression pool
temperature was maintained within Technical Specification (TS) limits
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by operating residual heat removal (RHR) system "A" in the
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suppression pool cooling mode from the remote shutdown panel.
This
startup test is complete with the exception of cold shutdown from
outside the control room.
The licensee's schedule is to demonstrate
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the ability to bring the reactor to cold shutdown from outside the
control room during test Condition 6.
No violations or deviations were identified in this area of
inspection.
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b.
Test 1-ST-23A, " Water Level Setpoint, Manual Feedwater Flow Change"
The SRI and RI witnessed selected performances of 1-ST-23A, " Water
Level Setpoint, Manual Flow Change," during this inspection period.
The licensee demonstrated that the feedwater level control system
converged rapidly to control vessel water level when vessel water
level demand step change were input into the master level controller
by the reactor operator.
Additional. reactor vessel level testing are
scheduled to be performed during test Condition 5 and 6 as part of
this startup test procedure.
No violations or deviations were identified in this area of
inspection.
3.
Startup Test Result Evaluation
During this inspection period, the SRI and RI reviewed startup test
results to verify that;
all changes, including deletions to the test
program had been reviewed for conformance to the requirement established
in the FSAR and Regulatory Guide 1.68; deficiencies had been adequately
addressed and corrective action completed; the licensee correctly analyzed
the test data and verified that it met the established acceptance
criteria; and the startup-organization as well as the facility review
committee (FRC) had reviewed and accepted the test results. The following
test packages were reviewed:
1-ST-17
System Expansion
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1-ST-31
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1-ST-26
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The following observations were made during the review of the above
startup test packages:
a.
Test 1-ST-17, " System Expansion"
The RI reviewed the completed test packages for 1-ST-17, " System
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Expansion," and verified tnat the startup test package had been
properly reviewed and that all test exceptions (TE) had been closed.
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The identified TEs involved violations of Level 2 criteria, which are
intended to identify pipe motion that does not move consistent with
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predictions, but does not involve pipe stresses outside the ASME code
limits.
Violation of the Level 2 criteria does not mean that the
piping response is unsatisfactory, but only that the piping is not
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responding in accordance with the theoretical predictions and that
further analysis of the' test results may be necessary.
The licensee
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closed these TEs based on a letter from General Electric Nuclear
Products and Engineering Services, dated January 21, 1986, which
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stated that the indicated Level 2 violations do not show any
significant overstressed conditions and are therefore acceptable.
No violations or deviations were identified in this area of
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inspection.
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b.
Test 1-ST-31, " Loss of Of fsite Power"
The SRI and RI reviewed 1-ST-31, " Loss of Offsite Power," to verify
that the test package had been properly reviewed and test data was
consistent with the established acceptance criteria.
The licensee
initiated TE 1 to identify a 3 second time difference between the
Division I and Division II standby diesel generators (0/G) energizing
their appropriate busses, resulting in the Division I chiller water
recirculation pump 1HVK* PIA and chiller 1HVK*CHLIA not starting.
In
addition, condition reports (CR) 85-0626 and 85-0622 were generated
to address switchgear 1A energizing 3 seconds later than 1B and the
failure of pump IHVK* PIA and chiller 1HVK*CHLIA to auto start
respectively.
CR 85-0626 was resolved based on subsequent testing of
Division I and Division II D/G which showed that both received the
correct start signal and reached rated frequency and voltage within
the time limits allowed by Technical Specifications.
The licensees
conclusion based on the test results was that differences in receiver
air pressure and diesel oil and water temperatures caused the
3 second time delay between Division I and Division II D/G reaching
rated voltage and frequency.
CR 85-0622 addressed the discrepancy between FSAR 9.2.10.5 (which
states that both divisions of the chilled water system will start on
a loss of offsite power incident) and the actual test results (which
showed that only a single division started).
Review of the chilled
water system design by the licensee revealed that if one division of
chilled water reaches rated flow before the second division receives
an auto start signal, the second division will not start. Based on
this design, Nuclear Plant Engineering (NUPE) requested that S&W
review this CR and prepare the necessary documentation changes to
provide a long term solution.
On December 19, 1985, NUPE provided
the operations department with a memorandum based on a preliminary
evaluation by S&W; this evaluation stated that only one division of
control building chilled water is needed for a loss of offsite power
incident.
NUPE dispositioned CR 86-0622 on January 13, 1986, cased
on the S&W preliminary evaluation, by initiating modification
request (MR) 86-0035, requesting that the control building
recirculation pump logic be modified to ensure that only one chilled
water division will start on recovery from loss of offsite power.
S&W then provided NUPE with a telog on January 22, 1986, of the
technical evaluation on heat release of electrical equipment in the
control building. This telog was not signed by a representative of
S&W, and did not provide formal calculations supporting the validity
of the technical evaluation.
However, on the following day, NUPE
issued a memorandum, S-CRB-8296, to operations stating that "this
memorandum serves to document an engineering analysis and subsequent
design changes which will allow one control building chiller to
operate following Loss of Offsite Power (LOOP) and during normal
plant conditions.
Only following a loss of Coolant Accident (LOCA)
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with normal station power available will it be necessary to have
operations manually start a second chiller to meet the total building
heat load. This operator action is not required until 30 minutes
after the event." This condition report was subsequently recommended
for closure on March 13, 1986, based on NUPE's corrective action
disposition of CR 85-0622, which relied on an informal and unverifed
analysis performed by S&W.
The FRC closed TE 1 to ST-31 on February 6, 1986, based on the above
NUPE analysis and corrective action recommendations for CR 85-0622.
The licensee's Quality Assurance Directive QAD - 11, " Test Control,"
Revision 4, requires that test results be documented, evaluated and
their acceptability determined by a qualified individual or group to
assure compliance with design and performance requirements.
This
evaluation is for the purpose of determining that any nonconforming
conditions are reported, properly dispositioned and corrected.
The NRC inspectors identified the disposition of TE 1 to 1-ST-31 by
the FRC, based on NUPE's corrective action disposition of CR 85-0622
(which relied on an informal and unverifed analysis performed by S&W)
as a failure to properly disposition the above test exception.
This
is an apparent violation (458/8608-01).
c.
Test 1-ST-26 " Safety Relief Valves"
The RI began a review of 1-ST-26, " Safety Relief Valves," during this
inspection period.
The results of this review will be documented in
a subsequent NRC inspection report.
No violations or deviations were identified in this area of
inspection.
4.
Startup Test Program Quality Assurance Review
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During this inspection period, the SRI and RI received the licensee's QA
program in the area of scheduling and implementation of QA audits and
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tracking of open Quality Assurance Finding Reports (QAFRs).
These areas
were reviewed to assure the licensee was meeting their audit schedule and
that open QAFRs were being reviewed to ensure timely resolution of audit
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findings.
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During this review, the NRC inspectors noted that the licensee had delayed
by 5 months the performance of audit 86-01-1, " Operations" and cancelled
the scheduled February 1986 audit of the startup program.
Also, the
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licensee's audit schedule dated December 5, 1985, indicated that the FRC
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activities were to be audited for the first time in October 1986, as part
of audit 86-10-I-SRPG (Safety Review Program).
The NRC inspectors
concluded that this scheduled audit of FRC activities was not timely in
that it did not account for the completion of FRC activities related to
the startup program.
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The review of the status of open QAFRs from the January and February 1986
QA activity reports, revealed that several corrective action completions
were overdue 30 days or more with some exceeding 90 days. The
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February 1986 activity report revealed a corrective action overdue status
of 1 QAFR overdue more than 30 days, 5 QAFRs overdue mora than 60 days,
and 15 QAFRs overdue more than 90 days.
The NRC inspectors discussed their concerns with audit scheduling and
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timely corrective action completions with QA management.
It was
discovered that a manpower shortage had existed in the QA audit group
since early January; this contributed to the audit scheduling problems,
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and the licensee had made a QAFR status computer data base transfer which
contributed to the QAFR statusing problem.
The correct QAFR status for
the Fe'oruary 1986 activity report was found to be five QAFRs with
corrective action overdue.
The failure to audit the FRC activities relating to the startup program
early in the life of the activity was identified by the NRC inspectors as
an apparent violation (458/8608-02).
The licensee QA management took immediate action to increase the QA audit
manpower to eight personnel (from a low of two auditors), to schedule an
audit of FRC activities in March 1986 (included in audit 86-03-I-STPG),
and to conduct a complete review of QAFR status. A QA activity report
issued on March 13, 1986, revealed no QAFRs with overdue corrective action
more than 30 days.
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The SRI and RI will monitor audit scheduling, QAFR status and QA
department staffing adequacy during future inspections.
5.
Operational Safety Verification
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The SRI and RI observed operational activities throughout the inspection
period and closely monitored operational events.
Control room activities
and conduct were observed to be well controlled and efficient.
Proper
control room staffing was maintained and access to the control room
operational area was controlled. The licensee was adhering to limiting
conditions for operation (LCO) as they occurred. Operators were
questioned regarding lit annunciators and they understood why the
annunciators were lit in all cases. Selected shift turnover meetings were
observed and all necessary information concerning plant status was being
covered in these meetings. A walkdown of the low pressure core spray
systen was conducted and the valves were observed to be in the proper
position.
No violations or deviations were identified in this area of inspection.
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6.
Safety System Walkdown
During this. inspection period, the SRI and RI performed a walkdown of the
low pressure core spray (LPCS) system to verify proper system alignment
for operability as required by Technical Specifications for Operational
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'Conditians 1, 2, and 3.
It was observed that:
accessible valves were properly aligned and control room indication
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indicated proper alignment for inaccessible valves;
no abnormal control room instrumentation readings or alarms were
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present;
no leakage from major components was present;
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the LPCS pump upper and lower bearing seal oil reservoirs were
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properly filled; and
accessible hangers and supports were intact.
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No anomalies were noted that would have affected LPCS system operability.
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However, based on this system walkdown, two conditions were identified and
discussed with the licensee.
These were that there appeared to be some
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inconsistencies with locking of vent and drain valves and that there were
apparent discrepancies with the system piping and instrument
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diagram (P&ID) which did not reflect proper valve positions for certain
instrument valves.
The licensee stated that they used the design drawings
to determine which valves should be locked as a minimum and some
additional valves were locked at the discretion of the operations staff.
Subsequent to this inspection, the licensee has issued an engineering
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action request to evaluate locked valves and to develop a consistent
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criteria for locking of valves.
This will be monitored by the NRC
inspector as an open item (458/8606-03).
Regarding the P&ID valve
position discrepancies, the licensee stated that they were presently
reviewing the P&ID for any needed corrections.
The operating procedures
valve lineups were correct for the specific cases noted and the P& ids were
to be revised to match the operating procedures. The issue of valve
position indication on P& ids is considered an open item (458/8606-04) and
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will be reviewed further during a future NRC inspection.
No violations or deviations were identified in this area of inspection.
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Emergency Drill
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The SRI and RI participated in the River Bend Station emergency drill
which was conducted on February 26, 1986.
The SRI and RI responded to the
declaration of-an unusual event (for drill purposes) and reported to the
control room at 1030 hours0.0119 days <br />0.286 hours <br />0.0017 weeks <br />3.91915e-4 months <br />.
The SRI and RI monitored the event from the
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control room until an alert status was declared.
The SRI then reported to
the technical support center (TSC) for the remainder of the drill.
The
emergency response capability of the licensee personnel in the control
room and TSC was observed to be well coordinated and efficient.
Observations by the SRI and RI were provided to the NRC emergency response
inspection team leader to provide additional inspector observations for
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the overall drill evaluation.
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8.
Site Tours
The SRI and RI toured areas of the site during the inspection period to
observe general work practices and gain knowledge of the facility.
No violations or deviations were identified in this area of inspection.
9.
Exit and Inspection Interview
An exit interview was conducted on March 20, 1986, with licensee
representatives (identified in paragraph 1).
During this interview, the
SRI reviewed the scope and findings of the inspection.
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