ML20031G032
| ML20031G032 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 10/01/1981 |
| From: | Beckman D, Greenman E, Hegner J, Troskoski W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20031G025 | List: |
| References | |
| 50-334-81-20, NUDOCS 8110200673 | |
| Download: ML20031G032 (45) | |
See also: IR 05000334/1981020
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U.S. NUCLEAR REGULATORY C0!EISSION
OFFICE OF INSPECTION AND ENFORCEMENT
Region I
Report No. 50-334/81-20
Docket No. 50-334
License No. DPR-66
Priority
Category _
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Licensee:
Duquesne Light Company
435 Sixth Avenue
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Pittsburgh, Pennsylvania
Facility Name: Beaver Valley Power Station, Unit 1
Inspection at: _Sh"ppingport, Pennsylvania
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Inspectors:
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D. A
kma
, Senior Resident Inspector
Dai;e sis,ned
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C.rt_.
2.t M
Date ignep
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er,gResident Inspct r
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W. M. Troskoski, Reactor Infector
Dat# signed
Approved by:
8. C C O*A b.
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__ Date signed
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E. G. Greenman, Chief, Reactor Projects
Section No. 2A
Inspection Summary:
Inspections on August 4 - September 7,1981 (Inspection Report No. 50-334/81-20).
Areas Inspected: Routine inspections by the resident inspector' (161 hours0.00186 days <br />0.0447 hours <br />2.662037e-4 weeks <br />6.12605e-5 months <br />) and a
region-based inspector (32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />) of:
licensee action on previous inspection findings,
plant operation, housekeeping, fire protection, radiological controls, surveillance
testing, maintenance, physical security, in office review of Licensee Event Reports,
onsite licensee event followup, reactor trip followup, unusual event followup, potential
deficiencies in structural designs, and licensee implementation of TMI action plan
requirements.
Results: Noncompliance: None in 12 areas. Two in two areas (Failure to notify NRC
of a reactor trip per 10CFR50.72, paragraph 3.d(3); and, Failure to implement and
maintain surveillance test. procedures, paragraph 3.d(10)).
C110200673 811002
PDR ADOCK 05000334
O
Region I Form 12
(Rev. April 77)
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DCS IDENTIFICATION NOS.
IE INSPECTION NO. 50-334/81-20
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No
Report Paracra2h
50-334 - 810816
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50-334 - 810708
4, 5
50-334 - 810722
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50-334 - 810719
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50-334 - 810807
4
50-334 - 810805
2,4,5
50-334 - 810731
4
50-334 - 8108G3
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_ DETAILS
1.
Persons Contacted
R. Balcerek, Nuclear Engineering and Refueling Supervisor
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J. Carey, Vice President, Nuclear Division
K. Grada, Superintendent of Licensing and Compliance
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R. Hansen, Maintenunce Supervisor
J. Kosmal, Radcon Supervisor
S. Lacey, Chief Engineer
L. Schad, Operations Supervisor
J. Sieber, Manager, Nuclear Safety and Licensing
J. Starr, Station Engineer
J< Wenkhous, Reactor Control Chemist
H. Williams, Station Superintendent
The inspectors also contacted other licensee employees and contractors
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during this inspection.
2.
Licensee Action on Previously Identified Inspection Findings
The NRC Outstanding Items (0I) List was reviewed with responsible licensee
personnel.
Items selected by the inspectors were subsequently reviewed
through discussions with licensee personnel, documentation review, and
field inspection to determine whether licensee actions specified in the
OIs had been satisfactorily completed. The overall status of previously
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identified inspection findings was reviewed, and planned and completed
licensee actions were discussed for those items not reported below.
(Closed)
InspectorFollowItem(78-24-02): Review corrective actions
and controls implemented for operating on RHR flows less than 3200 gallons
per minute. The inspector concerns involved with this item included:
(a) calibration of RHR flow indication for low (1000-2000 gpm) flow
ccnditions, (b) consideration for TS ,.1.1.3 and 3.9.8, Minimum RCS/RHR
Flows for Boron DMLtion, and (c) operation below the RHR low flow
annunciator setpoint for RHR System operation with the RCS drained down
to about the vertical centerline of the coolant loops. Additional
inspection of these activities is discussed in IE Inspection Reports
Nos. 50-334/80-27 and 81-08.
On August 11, 1981 the inspector reviewed BVPS Operating Manual (0M)
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Sections 1.10.2, RHR System Setpoints, Limitations, and Precautions,
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Revision 3 and 1.10.4.J. RHR System Operation When t% RCS is Partially
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Drained, Revision 4, confirming that operation in a drained down condi-
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tion requires special linear recalibration of RHP, flow indicator,
F-RH-605, and that OM Section 1.10.2 includes precautions for RCS
Boron Dilution pertinent to TS 3.1.1.3 and 3.9.8.
Additionally, OM
Section 1.7.4.N, Blender Dilution Operation, Revision 5, requires a
minimum RHR/RCS flow of 3000 gpm during dilution per TS 3.1.1.3.
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The BVPS Maintenance Manual (rel), Chapter 1. Section 0, Calibration
Program, Revision 7) Appendix 4,requirescalibrationoftheRHRflow
instrument (F-RH-605 at least once per eighteen months. The licensee
has established temporary Corrective Maintenance Procedure (CMP)
1-10-RH-F-605-1 Temporary Modification of RHR Bypass Flow Loop F-RH-605
for Linear Indication, Revision 1.
This CMP provides for linear recali-
bration of the instrument to permit accurate detemination of low system
flow values and establishes the low flow alarm setpoint at 1250 gpm.
The inspector reviewed MWRs Nos. 800828(datedJanuary 1-15,1980)
and 800763 (dated May 26-28,1980) which documented perfomance of the
CMPs on the resDective dates shown. The licensee's actions adequately
addressed the prior inspector concerns.
(Closed)
Inspector Follow Item (78-17-02): Maintenance of Shift Logs.
The inspector reviewed all operator logs for the period of August 8-11,
1981. This review focused on completeness of log data entries; followup
of antaalous readings, incorporation of revisions and Operating Manual
Change Notices, and maximum-minimum limits for logged parameters. Based
upon this and routine inspector review of the shift logs perfomed on a
daily basis, the inspectors concluded that the licensee was maintaining
and reviewing the logs as required. Deficiencies identified in the logs
were being addressed with corrective action initiated or complete.
Additional inspector review of the licensee's operating log surveillance
program is discussed below in conjunction with Violation 80-30-05.
(Closed)
Infraction (79-17-01): Failure to Properly Implement Procedures
for Locked Valve Control Review of Surveillance Data, and Calculation
of ECP. On August 21 and 22,1979, Valves 1-CH-26, 1-FW-27, and 1-RW-98
were found to be properly positioned but unlocked. No reason or authori-
zation for unlocking the valves could be established. The licensee com-
mitted to conduct a review of the administrative procedures with regard
to controls over padlocked valves.
In addition, several key in-line
safety related valve position checks were to be incorporated into the
logs and checked each shift. The inspector held discussions with the
Shift Supervisor to detemine that a review of the controls had been
conducted. BVPS Operating Manual (0M), Section 1.48.5.c, Lockout,
Revision 6, had been reviewed and revised by the licensee to incorporate
the above comitments.
In addition, the Nuclear Operators Log, BVPS OM
Section 1.54.7, Revision 19 requires that certain ESF valve positions
be checked on a shift basis. The inspector reviewed these logs and
conducted a field tour to verify that valve 1-FW-27 was locked in the
open position. No discrepancies were observed.
The estimated critical position (ECP) calculations perfomed on August
17 and 19, 1979 were not properly cornpleted in that Section 1.50.4.F,
Items D, E, and F and the preparer's and reviewer's signature blocks were
not complete. The licensee issucd a letter to all operating personnel
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dated September 7,1979 on Completion of Records for Operating
Procedures and Operating Surveillance Tests. The letter addressed
the need for correct documentation, reviewing and resolution of any
deviation from the Administrative and Operating Procedures. This
appears to have been effective as the ECP calculations completed on
July 30, 1981 were reviewed by the inspector and found to be properly
completed. The inspector had no further questions on this matter.
(0 pen) Violation (80-30-05): Failure to log a teminated surveillance
test in Shift Supervisor, Shift Foreman and Nuclear Control Operator
(Reactor Operator) Logs. The inspector reviewed the licensee's
corrective and preventive actions as discussed in the DLC response
letter of June 19, 1981.
The inspector confimed through personnel interviews that licensee
management interviews with and counseling of involved operators had
been conducted as stated. The inspector was unable, however, to locate
written documentation of the actions. On August 26, 1981, the station
Operating Supervisor issued an internal memorandum to the DLC Superin-
tendent of Licensing and Compliance documenting the past perfomance of
the interviews.
The inspector confirmed that special training for operations personnel
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regarding log keeping had been completed by July 1,1981 as comitted.
The inspector reviewed DLC Lesson Plan No. LP-SQS-54.1, training rosters
dated June 26, 30, July 9, and 17,1981, and training handout material
which collectively documented acceptable implementation of the comitment.
The inspector noted that six individuals had not completed the required
training as of July 28, 1981 due to absence or temporary reassignment.
These individuals had been identified by the DLC Training staff and were
to be rescheduled for the training.
The licensee had &lso committed to implement a special program of log
surveillance to monitor and ensure compliance with log keeping require-
ments. The inspector confimed that the station Reactor Engineer was
conducting critical log reviews on a daily basis and providing oral
reports to the station Operating Supervisor. Although these reviews
were resulting in identification and correction of log discrepancies
on a case-by-case basis, the inspector advised the Station Operating
Supervisor on August 13, 1981 that the informality of the program did
not provide records necessary for trend detemination or documentation
of corrections made for individual deficiencies. Additionally, licensee
plans for continuation periodic log surveillance (as specified by the
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above DLC letter) had not been fomalized. On August 26,1981, the
station Operating Supervisor issued an internal memorandum to the DLC
Superintendent of Licensing and Compliance stipulating that the station
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Reactor Engineer would continue daily surveillance of Control Room
logs until such time that a new Operations Coordinator position is
filled. A new system will be established for independent log reviews
at that time.
In the interim, the Reactor Engineer will submit sur-
veillance findings to the Operating Supervisor each Friday. The
inspector reviewed Log Review Memos for the weeks of August 17, 24,
and 31, 1981 and found them acceptable. Operating Supervisor dis-
position of the surveillance findings and establishment of a long
term program will be reviewed during a subsequent inspection. This
item will remain open pending completion of those actions.
(Closed)
Infraction (80-27-01): Failure to Establish and Implement
Procedures for Calibration of Remote ShutdoAn Panel Pressurizer Level
Indicator. On November 16, 1980, the inspector identified that the
licensee had failed to establish, implement, and maintain a written
procedure for channel calibration of a remote shutdown monitoring
instrumentation pressurizer level channel indicator, LI-RC-460A.
In a DLC letter dated July 21, 1981, in response to the NRC Notice
of Violation dated June 25, 1981, the licensee stated that the instru-
ment was properly calibrated on January 11, 1981 as part of a calibration
performed in accordance with Maintenance Surveillance Procedure MSP 6.42,
L-460 Pressurizer Level Protection Channel II, Calibration, Revision 6.
In addition, the indicator was included in the MSP procedure to prevent
recurrence of the missed calibration.
On August 21, 1981, the inspector reviewed MSP 6.42, L-460 Pressurizer
Level Protection Channel II Calibration, Revision 6, performed January
11, 1981 and verified that LI-RC-460A had been calibrated as stated.
The inspector also verified that the calibration of indicator LI-RC-460A
had been included as part of the MSP procedure. The inspector had no
further questions.
(Closed) Violation (80-27-10): Failure to maintain Operating Manual
controlled copies; missing pages and inadvertantly deleted temporary
changes. The inspector reviewed the licensee's actions as described
in a DLC response letter of July 21,1981. On August 12,1981 the
inspector confimed that the discrepant manual sections (BVPS OM
Section 1.37.1 and 1.7.4.K) were corrected and properly constituted.
The licensee had issued Memorandum No. BVPS: LGS:140, dated July 20,
1981, to all operating personnel, identifying this violation and
providing guidance for proper maintenance of controlled copy manuals.
The inspector confimed receipt and understanding of this memorandum
by interview of selected operating personnel.
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A portion of this violation involved inadvertant deletion of active
temporary changes (Operating Manual Change Notices) during insertion
of routine manual revisions which did not incorporate the temporary
changes. The licensee has begun annotating Operating Manual Revision
Transmittal sheets with instructions for removal or continuance of
Operating Manual Change Notices (OMCN). The inspector audited the
Shift Supervisor's controlled copy OM for proper insertion of the
following revisions and adherence to OMCN instructions:
BVPS OM Section 1.37.1, 480 Volt Station Service System, Issuc 2,
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Revision 1; no 0MCNs to remove;
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BVPS OM Section 1.55A.4, Operating Surveillance Test (OST) 1.6.2,
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Issue 1, Revision 12; no OMCNs to remove;
BVPS OM Section 1.55A.4, OST 1.6.4, Issue 1, Revision 12; no
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OMCNs to remove;
BVPS OM Section 1.55A.4, OST 1.6.6, Issue 1, Revision 12; no
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OMCNs to remove;
BVPS OM Section 1.7.4, Chemical and Volume Control System, Issue
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2, Revision 5; OMCN 81-248 removed; and,
BVPS OM Section 1.7.3, Chemical and Volume Control System, Issue
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2, Revision 1; OMC*i 81-254 removed.
The inspector discussed the annotation practices with the DLC Procedures
Engineer responsible for implementation and found him knowledgeable
of the prior deficiencies and current practice. The inspector additionally
determined that BVPS OM Section 1.48.3.E.5, Revision Identification,
Revision 18, had been approved by the Onsite Safety Committee and for-
warded to the Station Superintendent for approval and issuance. That
revision fonnalized the current practice and appears to adequately
describe controls necessary to prevent recurrence.
(Closed)
Infraction (80-09-12): Failure to Control Temporary Use of
Equipment Associated with DCP 201/202 Modifications, and
(Closed) Infraction (80-09-13): Failure to Adequately Control Documents
Associated with DCP 201/202 Modifications.
Turnover from construction forces to the Operating Department for
temporary use of systems affected by DCP 201/202, Ventilation System
Modifications, took place on January 19, 1980 via a " conditional
system release" in order to support the TS requirements for refueling
and associated activities. No apprc'ved proce?"re had been used to control
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the transfer of responsibility for or jurisdiction / control of the
system. At the time, the inspectors noted that the licensee had
already acknowledged deficiencies in this area and was developing an
improved turnover procedure that would address the inspectors' findings.
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The inspectors also detemined that as-built engineering information
associated with DCP 201/202 was not being properly controlled, dis-
tributed, and used with respect to the preparation, review, and approval
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of operating and surveillance procedures and was not available to support
the operation and maintenance of the equipment as current reference
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documents.
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On August 6, 1980, in response to the NRC Notice of Violation dated
July 8,1980, the licensee response letter identified the following
corrective measures to be taken to prevent recurrence:
Anstruction Division - Nuclear Procedure CDN J.7.3, System Release
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Turnover Procedure, issued May 20, 1980, amplifies instructions for
systea release.
It c1t-ifies interface requirements between the
Construction Department, the Onsite Engineering Group and the Power
Stations Department.
In addition, the procedure provides require-
ments for turnover of four copies of Type 1 as-built drawings (flow,
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elementary, wiring, and logic diagrams) for each Design Change
Package.
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Station Engineering Procedure SEP 2.3, Design Change Coordination,
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has been revised to control transfer of responsibilities during
equipment turnover. The procedure also requires controlled files
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of design change infomation to be maintained and controls for
updating station drawings with as-built information prior to
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station acceptance.
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On August 12-14, 1981 the inspector reviewed these procedures and
confimed that the actions stated in the licensee's August 6,1980
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letter were incorporated as stated.
In addition, the inspector reviewed
selected Design Change Packages which had been administered under the
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revised procedures to confim that the actions required in the procedures
appeared sufficient to provide acceptable control of the design change
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process. The following DCPs were reviewed:
DCP No. 376, Supports on Safety Related HPV's and LPD's Inside
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Containment;
DCP No. 325, Steam Generator Moisture Carryover Modification;
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DCP No. 345, Safety Injection System Valve SI-358 Removal;
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DCP No. 299, Instruuentation Loops: F-FW-100A, B, and C;
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Annunciators for M0V's; and
DCP No. 292, Pressurizer PORY and Safety Valve Indication.
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The inspector confirmed that the DCPs were being processed in conformance
with the above procedures.
In addition, through discussions with the
cognizant DLC engineers responsible for conducting turnover of design
change packages, the inspector confinned that the procedures provided
sufficient clarification of responsibilitias and document control. The
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inspector had no further questions.
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(Closed) Infraction.(80-09-11): Failure to Implement and Maintain
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Surveillance Tests as a Result of Design Change Packages No. 201/202
Modifications. Based on imediate corrective actions taken by the
licensee at the time of the findings, the licensee was requested to
only identify those actions taken to prevent recurrence in the response
to the Notice of Violation. A DLC letter of August 6,1980, in response
to the NRC Notice of Violation dated July 8,1980, stated that the
following actions had been implemented to maintain procedures to
accurately reflect as-built system conditions, and ensure that existing
deficiencies were promptly identified to management to pemit initiation
of appropriate corrective actions.
Station Engineering Procedure (SEP) No. 213, Design Change Coordina-
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tion, had been revised to include provisions for maintaining a
controlled file of design change infomation at the station for use
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by station personnel during procedure preparation / revision.
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addition, the SEP was revised to include provisions for completion
of all new procedures or revisions prior to station Operational
Acceptance of design changes; and
A letter was issued to all station personnel concerning their
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responsibilities when signing documents / procedures.
During August 12-19, 1981 the inspector reviewed Station Engineering
Procedure 2.3, Design Change Coordination, and confirmed that the actions
specified above were included in the procedure. Revision 2 to SEP 2.3,
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dated May 23, 1980, included, among other changes, a Design Change Turn-
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over Checklist, which specifically identified requirements for pre-
operational and operational acceptance. Revision 3 to SEP 2.3, dated
June 2, 1980, included a equirement for completion of Station Drawing
Field Update as a requirement for Operational Acceptance. Revision 4
to SEP 2.3, dated June 14, 1980, modified the Station Drawing Field
Update completion requirement to be a Preoperational Acceptance Require-
ment.
In addition, the inspector reviewed several Design Change Packages
and confimed that they had been processed in accordanu with the SEP's
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piVcedural requirements. The Design Change Packages reviewed are identi-
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fied in conjunction with Violations 80-09-12 and 80-09-13 discussed above.
In addition, the procedure was discussed with the DLC Senior Engineer and
cognizant station engineers who appeared familiar with its provisions.
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The inspector also reviewed internal DLC memorandum, BVPS:HPW:278,
dated August 5,1980, issued to all BVPS Station Personnel. The
memo, entitled " Responsibilities of and Meaning of Verifier's Signature
on a Document," stated station policy on the responsibilities of and
meaning of a verifier's signature on a dortunent. The inspector had no
further questions regarding this matter.
(Closed)
Inspector Follow Item (79-22-11): DLC Supplemental Report
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for LER 79-16 on Cable Routing Errors. The licensee submitted LER
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79-16/03L-1 and LER 79-16/03L-2 on August 2, 1979 and January 28, 1981,
respectively, as supplemental reports which discussed DLC followup
actions regarding cable tray routing modifications / verification.
Inspector
review of the additional submittals detemined the licensee's actions
to be acceptable.
(Closed)
Inspector Follow Item (80-30-08): Confinn issuance of supple-
mental Licensee Event Report (LER) regarding repeated Chlorine Detector
Failures. The chlorine detectors provide automatic isolation of the
Control Room ventilation system in the event of a ma.ior onsite or near-
site chlorine spill. The licensee has experienced long-term difficulty
in implementing effective corrective action for repeated detector failures.
Subsequent to a January 7,1981 comitment to submit a supplemental LER
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documenting the results of an engineering review of the problem and the
actions taken to resolve the recurrent chlorine detector failures, the
following additional LERs were issued to report additional detector
failures: LER 80-107, 115, 118; 81-05, 07, 11, 12, 22, 27, 35, 39, 50
and 52.
In lieu of a supplemental report, the LERs served to provide
a continuing narrative of licensee actions being taken in attempts to
correct the recurrent failures. These actions included:
frequer.t wick
replacement, change of wick type, increasing water purity, additional
personnel training, frequent cleaning of glass electrolyte orifices,
additional testing to provide a sufficient data base for engineering
review, and design modifications to provide better ventilation for the
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electrolyte reservoir. Subsequent to issuance of LER 81-050/03L, the
design modification to provide better ventilation was implemented and,
with one exception, failures have not recurred since May 13, 1981.
Based on the apparent success of the ventilation modification and the
continuing update provided by the LERs listed above, the inspectors
had no further questions.
(Closed)
Inspector Follow Item (80-30-13): Confirm issuance of
supplemental report for LER 80-91, Low Boren Concentration in Boron
Injection Tank. The original LER contained erroneous infomation
regarding th' cause of the low boron concentration in the Boron In.iection
Tank. After inspector review of the original LER and subsequent dis-
cussion with cognizant licensee personnel, the Station Superintendent,
on January 7,1981, comitted to issue a supplemental LER to correct the
erroneous cause description. LER 80-91/03L-1 was issued on January 29,
1981.
Inspector review of the revised LER determined that the revised
cause description was accurate and had no further questions.
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(Closed) Unresolved Item (81-15-01): DLC to strengthen barriers for
Vital Area ventilation dampers, grills, and other openings. On July 6,
1981 the station Security Supervisor issued Engineering Memorandum No.
20765 to the Engineering and Construction Division Onsite Engineering
Group (OEG) requesting an evaluation of station Vital Area barriers for
potential vulnerability and strengthening of barriers found less than
adequate.
The barriers specifically identified as less than adequate
by the inspectors during IE Inspection No. 50-334/81-15 (diesel generator
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rooms) have been acceptably strengthened ano reviewed by the resident
inspectors. The licensee's program for evaluation and strengthening of
other barriers is continuing and will be routinely reviewed during future
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inspections by NRC:RI.
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(Closed)
Inspector Follow Item (79-09-01): Review training administered
in accordance with IEB 79-06A. The inspector reviewed the attendance lists
for Training Module 6, Incident at TMI. From these lists, the inspector
determined that all licensed personnel completed the required course. The
lesson plans were reviewed in a previous inspection (IE Inspection No. 50-
334/79-09).
(Closed) Deficiency (80-23-01): All Licensed Reactor Operators and Senior
Reactor Operators to Review All Abnormal Procedures. BVPS Training Manual
Section 2.2.4.4, Individual Study, Subsection (h), specifies that all
licensed personnel perform reading assignments to review all Abnomal and
Eraergency Procedures each year. On a sampling basis, the ins
reviewed the BVPS Licensed Operator Requalification Sunnpary,pectorSection 7,
Abnomal and Emergency Procedure Review, for saveral SR0s and R0s. The
review covered CY 1980, as the 1981 cycle was still in progress. The
inspector confimed that the individuals whose reccrds were reviewed had
completed the required reading assignments and W no further questions
on this item.
(Closed)
InspectorFollowItem(80-23-02): Completion of Review of May
80 Annual Requalification Exam by Chief Engineer and Station Superintendent.
The training records of several individuals chosen at random were reviewed
by the inspector to verify that the Requalification Exam results were
reviewed by the Chief Engineer and Station Superintendent. Based on
the completed signature sheets documenting said review, this item is closed.
(Closed)
InspectorFollowItem(80-23-03): Implementation of Additional
Training Program Requirements Specified in Denton's March 28, 1980 letter
to all licensees. The licensee revised Section 2 of the BVPS Training
Manual to incorporate new requirements in the Nuclear Operator Training
and Licensed Operator Training Requalification Programs. These requirements
included a minimum overall average score of 80%, with 70% being the
minimum for any one section. Anything less than the above criteria requires
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an accelerated training program for the individual operator in the.-
specific area (s) of weakness. The inspector reviewed the records
of several licensed operators to verify that the program was in place
and functioning as stated. This review showed that individual programs
were identified and tailored to meet the criteria stated in Section 2.
The inspector had no further quesLions on this matter.
(0 pen)
Inspector Follow Item (81-18-02): DLC to audit and correct
erroneous instrument calibration stickers.
During this inspection, the
inspectors confirmed that DLC had completed the audit and was initiating
corrective actions but the licensee's actions were not reviewed in detail.
The inspectors, however, identified additional discrepancies in instrument
calibration stickers as discussed in paragraph 3.d of this report. This
item will remain open pending detailed NRC:RI review of the licensee's
actions during a subsequent inspection.
(0 pen)
Inspector Follow Item (81-18-05): Review licensee long-tem
actions for battery charger output breaker trips due to high ambient
temperatures. Additional inscector review of this item is documented in
paragraph 5 of this report in conjunction with LER 81-71/03L. This item
will remain open pending centinuing inspection of the licensee's progress
in developing effective lcng-tem corrective action.
3.
Plant Operations
a.
General
Inspection tours of selected plant areas were conducted during both
day and night shifts with respect to Technical Specification (TS)
compliance, housekeeping and cleanliness, fire protection, radiation
control, physical security and plant protection, operational and
maintenance administrative controls.
Acceptance criteria for the above areas include the following:
BVPS FSAR Appendix A, Technical Specifications (TS)
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BVPS Operating Manual (OM), Chap.s 18, Conduct of Operations
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OM 1.48.5 Section D, Jumpers and Lifted Leads
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OM 1.48.6, Clearance Procedures
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OM 1.48.8, Records
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OM 1.48.9, Rules of Practice
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OM Chapter 55A, Periodic Checks - Operathg Surveillance Tests
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BVPS Maintenance Manual (PN), Chapter 1, Conduct of Maintenance
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10 CFR 50.54(k), Control Room Manning Requirements
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BVPS Station Administrative Procedures (SAP)
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BVPSPhysicalSecurityPlan(PSP)
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Inspector Judgement
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b.
Areas Inspected
During the course of the inspection the inspectors made
cbservations and conducted multiple tours of plant areas,
including:
Control Room
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Primary Auxiliary Building, including High Radiation Areas and
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Loose Surface Contamination Areas
Turbine Building
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Service Building
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Main Intake Structure
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Main Steam Valve Room
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Purge Duct Room
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East / West Cable Vaults
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Emergency Diesel Generator Rooms
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Containment Airlock Area
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Penetration Areas
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Safeguards Areas
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Various Switchgear Rooms / Cable Spreading Room
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Protected Area
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c.
Observations
(1) Conformance with Technical Specifications
Through observation of Control Room monitoring instruentation
and annunciators, log review, and direct observation of selected
equipment, the inspectors verified that instruentation and
systems required to support operations were in confomance with
the Technical Specification (TS) Limiting Condition for
Operations (LCO). Verification of confomance to the following
Technical Specification LCOs was conducted frequently:
Minimum Temperature for Criticality
Boric Acid Flowpaths
Boric Acid Transfer Peps
Borated Water Sources
Movable Control Assemblies Group Height
Position Indicator Channels
Control Rod Insertion Limits
TS 3.3.3.5
Remote Shutdown Instrumentation
Axial Flux Difference
Reactor Trip System Instrumentation
Radiation Monitoring Instrumentation
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ESF Actuation System Instrumentation
Pressurizer Relief Valves
RCS Leakage Detection Systems
RCS Chemistry
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ECCS Subsystems
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Boron Injection Tank
Refueling Water Storage Tank
Quadrant Power Tilt Ratio
Containment Air Locks
Containment Pressure
Containment Temperature
Containment Quench Spray System
Containment Recirculation Spray System
Auxiliary Feedwater System
Primary Plant Demineralized Water
Component Cooling Water System
Residual Heat Removal System
Reactor Plant River Water Systems
Auxiliary River Water System
A.C. Sources
A.C. Distribution - Operating
D.C. Distribution - Opera +.ing
In addition, the inspectors conducted periodic visual channel
checks of Reactor Protection System and Engineered Safety
Features instrumentation to confirm the availability of safety
related equipment. The inspectors verified that selected
instruments were calibrated, functional, and that demonstrated
parameters were within Technical Specification limits. The
inspectors independently verified valve positions for selected
valves in the following systems: Quench Spray, Auxiliary Feed-
water, Low Head Safety Injection,
High Head Safety Injection
systems, and Chemical and Volume Control Systems.
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(2) Radiation Controls
(a) Radiation controls, including posting of radiation areas,
the conditions of step-off pads, disposal of protective
clothing, completion of radiation work permits, cotopliance
with Radiation Work Pemits, personnel monitoring devices
being worn, cleanliness of work areas, radiation control
job coverage, area monitor operability (portable and
pemanent), area monitor calibration, and personnel frisk-
ing procedures were observed on a sampling basis. The
inspector also conducted independent radiation surveys
of various posted areas to verify that radiation levels
were in accordance with the posting.
(b) The inspector reviewed the following Radiation Work
Permits and Radiation Access Contrc' Pemits for
corpleteness:
RWP 8123, Charging Pump Cubicles, 735' Elevation PAB,
--
dated August 5,1981, for various valve checks /
markings in charging pump cubicles.
RWP 8122, PAB 722' Elevation, Hallways and Charging
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Pump Cubicles, dated August 4,1981 for Pipe Hanger
Inspection.
RWP 8137, PAB 735' Elevation at RM-RW-101, dated
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August 8,1981, to modify piping for River Water
Radiation Monitor RM-RW-101.
RWP 8194, 735' Elevation PAB Dogasifier dated
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August 18, 1981, to repair let K on BR-E-12A1.
(c) Stack monitor recorder records wei e reviewed for indications
of unplanned releases. The results of selected liquid
radioactive releases made during the period were reviewed
to verify conformance with rege11 tory and administrative
requirements prior to release:
RWDA - I.fquid,No. 01683, Discharge of Steam Generator
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Drains Tank 7B, performed August 4,1981;
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RWDA - Liquid, No. 01686, Discharge of Steam Generator
Drains Tank 78, perfomed August 19-20,1981; and
RWDA - Liquid, No. 01689, Discharge of Laundry Tank 6A,
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performed September 2,1981.
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The Control Room log for Radiation Monitor setpoints
was reviewed on a weekly basis and actual setpoints for
the following radiation monitors were confimed to be
correct:
RM-LW-104
- Liquid Waste Effluent
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RM-GW-108A/B - Gaseous Waste Disposal Discharge
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RM-VS-100
- Condenser Air Ejector Discharge
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RM-VS-107A/B - Ventilation Vent Discharge
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(3) Plant Housekeeping
Plant housekeeping conditions including general cleanliness
conditions, control of material to prevent fire hazards,
maintenance of fire barriers, fire barrier penetrations,
and verification of posted fire watches in these areas were
observed. The inspector verified that selected fire ex-
tinguishers were accessible and inspected on schedule, that
fire alarm stations were unobstructed, that Cardox systems
were operable and that adequate controls over ignition
sources and fire hazards were being maintained.
Fluid leaks. No fluid leaks were observed which had not
been identified by station personnel and for which corrective
action had not been initiated, as necessary.
Piping vibration. No excessive piping vibrations were
observed and no adverse conditions were noted.
Selected pipe hangers and seismic restraints were observed
and no adverse conditions noted.
(4) Control Room Observations
Control Room manning was observed periodically during
the inspection on daily visits during the normal work
week, on backshifts, and on weekends, and was confimed
to meet or exceed the requirements of Technical Specifica-
tions and the BVPS Operating Manual.
In addition, the
inspectors periodically observed shift turnovers to verify
that continuity of operations was maintained and that
personnel assuming responsibility for plant operation
were fully cognizant of plant systems status. The
inspectors periodically questioned shift personnel
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regarding their awareness or plant condition, procedure changes,.
facility configuration, and knowledge of emergency procedures.
The inspectors toured the Control Room on a daily basis in order
to:
Verify access to the Control Room was controlled in
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accordance with licensee procedures;
Review Shift Supervisor, Shift Foreman, Nuclear Control
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Operator, and Nuclear Operator logs and records to obtain
information concerning operating activities and trends;
Conduct discussions with operators concerning reasons for
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selected lighted annunciators and verify that the reasons
for them were understood and corrective action, if required,
was being taken;
Verify the operability of the Reactor Protection System
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and Engineered Safety Features Systems;
Verify boric acid concentrations, volumes, temperatures,
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and flowpaths were in conformance with Technical Specifi-
cations;
Verify by examining panel indications that the required
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emergency power sources were available; and
Verify by examining panel indications, log review, and
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interviewing operators that required containment configur-
ation was established.
Except as noted in paragraph 3.d below, inspector concerns or
questions resulting from these daily reviews were acceptably
resolved by licensee personnel.
(5) Surveillance Tests
(a) The inspectors reviewed completed surveillance tests
to verify that: surveillance tests were being completed
as scheduled; test results were being reviewed cccording
to approved procedures; and, appropriate corrective actions
were initiated as necessary. The following records of
completed Operational Surveillance Tests (OST) were reviewed:
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OST 1.39.1 - Weekly Station Battery Check, Revision 6,
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completed August 11, 1981.
OST 1.11.13 - Boron Injection Surge Tank Level
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Verification, Revision 25, completed August 11, 1981.
OST 1.12,3 - Steam Jet Air Ejector Suction Line
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Isolation Valve Position Verification, Issue 1,
complet=3 August 11,1981.
OST 1.13.3 - 1A Recirculation Pump (IRS-P-1A) Dry
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Test, Revision 24, completed August 11, 1981.
OST 1.6.2 - Reactor Coolant System Water Inventory
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Balance, Revision 12, completed August 10,1981.
OST 1.33.8 - Weekly Diesel Engine Driven Fire Pump
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Operation Test, Revision 11, completed August 10, 1981.
OST 1.33.7 - Weekly Motor Driven Fire Ptap Operation
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Test, Revision 29, completed August 10, 1981.
OST 1.20.3 - FC-P-1B Fuel Pool Pump Operkbility Test,
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Revision 4, completed August 7, 1981.
OST 1.13.6 - 2B Recirculation Pump (lRS-P-28) Dry
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Test, Revision 24, completed August 7, 1981.
OST 1.48.3 -Control Board Checklist, Revision 7,
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completed August 5-6,1981.
OST 1.7.8 - BA Storage Tanks and RWST Level and Tempera-
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ture Verification, Revision 17, completed August 6,1981.
OST 1.24.1 - SG Auxiliary Feed Pump Discharge Valves
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Exercise, Revision 22, completed August 6,1981.
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OST 1.7.2 - Boric Acid Transfer Pump (1CH-P-23)
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Operational Test, Revision 21, completed August 6,1981.
OST 1.11.13 - Boron Injection Tank Surge Tank Level
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Verification, Revision 25, completed August 7,1981.
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OST 1.36.2 - Diesel Generator No. 2 Monthly Test,
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Revision 22, completed August 18, 1981.
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OST 1.7.1 - Boric Acid Transfer Pump (1CH-P-2A)
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Operational Test, Revision 21, completed August
18, 1981.
OST 1.11.10 - Baron Injection Flow Path Power
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Operated Valve Exercise, Revision 28, completed
August 18, 1981.
OST 1.24.4 - Turbine Driven Auxiliary Feed Pump
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Test,1FW-P-2, Revision 22, completed August 15, 1981.
OST 1.11.13 - Boron Injection Surge Tank Level
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Verification, Revision 25, perfomed August 20,1981.
OST 1.32.1 - Chemical Waste Sump pH Monitor Opera-
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bility Check, Revirion 4, perfomed August 20, 1981.
OST 1.47.1 - Containment Airlock Test, Revisic.122,
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performed August 20, 1981.
OST 1.24.2 - Motor Driven Auxiliary Feedwater Pump
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Test (1FW-P-3A), perfomed August 20,1981.
OST 1.20.1 - Spent Fuel Pool Level Verification,
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perfomed August 20, 1981.
OST 1.48.3 - Control Board Check List, Revision 7,
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OMCNs81-237
- 289, -268, -234, perfomed August
19, 1981.
OST 1.44A.6 - Chlorine Detection System and Control
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Room Breathing Air Header Bottles Operability Check,
Revision 10, perfomed August 19, 1981.
(b) The inspectors observed portions of the following
surveillance or maintenance activities to verify that
the test instrumentation was calibrated, redundant
systems or components were available for service,.
approved procedures were used, and work was perfomed
by qualified personnel:
OST 1.36.1 - Diesel Generator No. 1 Monthly Test,
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Revision 22, perfomed August 7,1981;
MSP 2.04 - Power Range Neutron Flux Channel N-N142
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Quarterly Calibration, Revision 12, perfomed August
10, 1981; and
OST 1.30.2 - River Water Pump 1A Test, Revision 30,
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performed August 19,1981.
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(6) Maintenance
On August 18, 1981, the inspector observed work preparation
efforts for a Boron Recovery System Degas Heat !!xchanger
repair. The work was properly authorized and , or. ducted in
accordance with Maintenance Work Request No. 817510, Investigate
and Repair Leak on Bottom of Heat Exchanger.
The inspector
also confirmed that activities and radiation levels / postings
were in accordance with appropriate administrative / radiological
controls. The inspector confirmed that use of protective
clothing and respirators, radiation levels, and personnel
monitoring practices were in accordance with Radiation Work
Permit No. 8194, 735' Elevation PAB A Degas to Repair Leak
cri SR-E-12A1.
(7) Temporary Operating Procedures (TOP)
The inspectors reviewed Temporary Operating Procedures to
determine whether: the procedures had been properly Nviewed,
approved and issued; that plant operations directed by the
procedures were in accordance with the requirements of the
facility TS and QA program; and that procedures were properly
implemented and their performance documented.
TOP 80-22, High-High Setpoint Calculation for LW-104,
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Revision 2, issued July 7,1981.
TOP 81-25, Two Man Rule in Primary Auxiliary Building,
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Diesel Generator Building, Switchgear Area, Screenhouse,
and Chemical Addition Building, Revision 3, issued August
17, 1981.
TOP 81-28, Draining 4B Coolant Recovery Tank to Liner,
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Addendum, Revision 1, issued August 27, 1981.
TOP 81-31, River Water System Operating While Dredging
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Near Intake, issued August 7,1981.
TOP 80-32, Cleaning Out Transfer Section of Spent Fuel
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Fool, issued August 13, 1981.
(8) Equipment Control Procedures
Equipment control procedures used by the licensee to restrict
plant activities were examined to verify that tags were
properly filled out, posted, and removed as required by
approved procedures. The inspectors reviewed logs and
records for completeness. The inspectors verified proper
posting of the tag controls on the following systems:
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Safety Injection
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Chemical and Volune Control
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Boron Recovery
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Reactor Protection
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Radiation Monitoring
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The following Equipment Clearance Permits (tagouts) were
reviewed for proper completion and for posting:
473667, BR-TK-4B Equipment and Area Permit, issued
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July 20,1981.
473670,125 VDC Circuit - Steam Generator Blowdown Auto-
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isolation Modifications, issued July 22, 1981.
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459013, Repair of Radiation Monitor RM 213, issued
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August 29, 1981.
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459808, Repair Boron Injection Tank Flow Instrument
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FT-SI-934.
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459888, Repair Degasifier Heat Exchanger BR-E-12Al,
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issued August 17, 1981.
459894, Replace piping for Radiation Monitor RM-RW-101,
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issued August 29, 1981.
Additionally, on September 2,1981, the inspector audited the
Caution Tag Log active entries versus posting. From a sample
of 10 tags reviewed, one instance of misposting (tag on
MOV-Sl-864B vice -864A) was identified. Expansion of the
sample to 40 tags identified no further discrepancies. The
licensee promptly corrected the misposting. The inspector
considered the single discrepancy to be an isolated case and
had no further questions on this matter.
(9) Plant Security / Physical Protection
Implementation of the Physical Security Plan was observed
in the areas listed in paragraph 3.b above with regard to
the following:
Protected area barriers were not degraded;
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Isolation zones were clear;
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Persons and packages were checked prior to allowing
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entry into the Protected Area;
Vehicles were properly searched and vehicle access to
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the Protected Area was in accordance with approved
procedures;
Security access controls to Vital Areas were being
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maintained and that persons in Vital Areas were properly
authorized;
Security posts were adequately manned, eo;ipped, and
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security personnel were alert and knowir;geable regarding
position requirements, and that written procedures were
available; and
Adequate lighting maintained.
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d.
Findings
(1) During review of Caution Tag postings discussed in paragraph
3.c(7) of this report, the inspector noted that the Caution Tag
posted on the control switch motor operated valve MOV-SI-844A
was annotated to indicate that a relief valve (RV-SI-845A)
serving the Low Head Safety Injection Header isolated by
MOV-SI-864A was gagged. The Control Room status board did
not reflect this condition and operators consulted by the
inspector could not personally confim whether the valve
was gagged nor provide the specific reason for gagging.
During discussions with shi#t supervision and the station Chief
Engineer, the inspector w , .-fomed that pressure surges from
LHSI Pump starts during routine testing had periodically caused
RV-SI-845A to lift and incompletely reseat, draining water to
the Safeguards Area sump and generating undesirable radwaste.
As a result, the valve had been gagged pending modification.
The inspector reviewed the status of Design Change Package
(DCP) No. 324, established for replacement of the existing
valve model with one considered more reliable for the specific
service. The Chief Engineer also confimed the valve was actually
gagged. The inspector was advised by the Chief Engineer and
,
the Nuclear Engineering and Refueling Supervisor that the valve
'
had been scheduled for replacement during the Cycle II-III
l
refueling outage (early 1982). The valve vendor had recently
advised the licensee that the replacement would not be available
until August 1982, after the outage. The inspector reviewed
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DLC Engineering Memorandum (EM) No.10767, dated July 6,1981,
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which addressed the delay in delivery and discussed alternatives.
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On August 21, 1981 the Chief Engine r advised the inspector
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that the existing valve would be modified with new internals
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to correct the undesirable lifting characteristics during the
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Cycle II-III outage and that the new valves would be either
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installed or held for spares upon arrival in 1982.
Relative to the LHSI system status with the valve gagged, the
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4
inspector reviewed the system lineup and confimed actual valve
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positions, concluding that compliance with the provisions of
d
the MOV-SI-864A Caution Tag would provide adequate overprussure
,
protection for the affected piping. The relief valve is in-
stalled to prevent overpressurization due to backleakage from
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the RCS into low pressure design piping. The existing valve
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alignment accomodates this concern.
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The inspector additionally confimed that the gagged status of
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the valve was added to the Control Room status board.
No unacceptable conditions were identified.
(2) At 12:26 p.m. on August 14, 1981 while at 100% power, a turbine
trip-reactor trip occurred due to low Electro-Hydraulic (EH)
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fluid system pressure. The EH High Pressure Fluid System regulates
main turbine throttle, governor, reheat stop, and interceptor
,
steam valve positions.
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About noon, operators were attempting to clear a high level
,
alarm in the Control Room for the EH fluid reservoir by draining
5
the reservoir to its nomal level.
During the evolution, the
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in-service EH pump (LO-P-98) tripped. Normal auto-start of
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the redundant 9A pump did not occur.
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Flant response to the reactor trip was noma 1.
The inspector
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entered the Control Room shortly after the trip and monitored
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the licensee response. The inspector independently verified
i
that selected primary and secondary system pressures, tempera-
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tures, and levels remained within normal operating limits. ' The
{
inspector also reviewed radiation monitoring data to confim
t
that no inadvertent release of radioactive materials had
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occurred as a result of the trip.
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As a result of discussions between the acting station superin-
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tendent and the resident inspector en August 14, 1981 the acting
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station superintendent committed to identifying and correcting
the problems associated with the EH system prior to returning
the system to operation. Subsequet licersee investigation was
not able to positively detemine the reason for the failure of
the running pump and was unable to duplicate the initiating
event. However, normal auto-start of the redundant pump also
did not occur due to cn apparent spurious Low-Low EH reservoir
level' signal which blocks any pump start on low reservoir level
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to provide pump protection. The licensee defeated the
Low-Low EH fluid level trip function and instituted periodic
surveillance of EH reservoir level pending completion of
troubleshooting activity on the faulted circuit. A low
reservoir level alam remained operable to provide warning
to operators.
The reactor was made critical at 3:08 p.m. on August 14 and
again at 10:17 p.m. (the reactor tripped during initial startup
as a result of sluggish bypass-to-main feedwater regulating
valve flow control response). The main generator unit was
synchronized at 10:43 p.m. and the plant returned to nomal
power operation en August 15, 1981. The inspector had no
further questions regarding this event.
(3) On August 26, 1981, 10:25 p.m., while at 100% power, a turbine
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trip-reactor trip occurred as a result of an Electrohydraulic
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(EH) Fluid System malfunction. A spurious signal was initiated
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by an EH Governor Overspeed Protection Circuit resulting in the
main turbine governor valves going shut and initiating the trip.
The inspector reviewed and observed the licensee's response to
the trip and corrective actions, including notification to NRC
of the trip in accordance with 10CFR50.72(a)(7), Notification
of Significarr. Events, and found the licensee's action to be
acceptable except as further discussed below.
l
The reactor was subsequently made critical at 2:04 a.m.,
August 27. A second reactor trip occurred at 4:40 p.m. on
August 27 during plant startup and return to power operation
as a result of a Low-Low level in the "C" Steam Generator.
The plant returned to power operation on August 28, 1981.
10CFR50.72(a)(7) requires the licensee to notify the NRC
Operations Center within one hour of any event resulting in
manual or automatic actuation of Engineered Safety Features,
'
including the Reactor Protection System. During a routine
review by the inspector of Control Room logs on August 28, 1981,
it appeared that no such notification had occurred. The
inspector discussed the matter with the station Operating Super-
visor who stated that, due to an administrative oversight, the
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Nuclear Shift Supervisor had failed to inform the NRC Operations
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Center of the reactor trip. The inspector infomed the Nuclear
Operating Supervisor that no imediate corrective action in
tems of placing a late notification was necessary since the
purpose of the call was to provide prompt notification of
significant events and notification had already been made via
the inspector. The infomation then available to the inspector
and the fact that the plant response to the trip was normal
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25
indicated that a notification in accordance with the require-
ments at that time would be unnecessary. However, the inspector
infomed the Operating Supervisor that the failure to notify the
NRC Operations Center within one hour of the trip in accordance
with 10CFR50.72 was an item of noncompliance.
(81-20-01).
(4) A small control power transformer inside the Boron Injection
Tank (BIT) Recirculation Fump (SI-P-38) breaker enclosure failed
and caught fire about 12:30 a.m., August 7, 1981. The fire
was isolated to the individual breaker enclosure, located in
emergency Motor Control Center No. MCCl-E4, and was extinguished
within 1-2 minutes by operators working in sight of the equipment.
The breaker and associated pump were rendered inoperable. The
redundant pump was not installed but was available for installa-
tion. Recirculation flow through the BIT was lost until 4:37
a.m.
The inspector became aware of this incident through routine
log review about 7:00 a.m., August 7 and reviewed the licensee
repair activities and compliance with TS 3.5.4.1, Boron Injection
Tank, and TS 3.5.4.2, Heat Tracing.
Onshift operators called out offshift electrical maintenance
personnel who temporarily replaced the failed breaker with that
from the redundant but uninstalled pump (SI-P-3A) by abgut 4:15
a.m.
The TSs above require maintenance of at least 145 F BIT
solution temperature. At 4:37 a.m., OST 1.11.13, Boron Injection
Tank Surge Tank Level Verification, Revision 25, was completed,
verifying the operability of the pump, BIT, and BIT heat tracing /
solution temperatures.
The failed transformer was replaced on the 0000-0800 shift,
August 7, and was reinstalled later in the day. Prior to
reinstallation, the inspector reviewed Maintenance Work Request
No. 811906, authorizing the repairs, inspected the failed unit,
and confimed that the transfomer was replaced with a proper,
certified spare, by qualified personnel, and with appropriate
Quality Control authorization. The inspector identified no
unacceptable conditions.
(5) Boron Injection Tank (BIT) Bypass Valve Circuit Breaker Found
Deenergized.
Around 4:50 p.m., August 5,1981, a circuit breaker for a Safety
Injection System motor operated valve was indicated to be in the
Advisor (STA) power unavailable) during a routine Shift Technical
off position (
surveillance of the main centrol board. The STA,
perfoming OST 1.48.3, Control Board Check, observed that the
indicating lights for the BIT Bypass Valve (M0V-SI-869B) were
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26 ~
out on the main and redundant control boards. The circuit
breaker, located on 480 VAC Motor Control Center MCCl-E6 in
the East Cable Vault of the Primary Auxiliary Buf1 ding (PAB)
was checked, found off (but not tripped), and was reclosed at
The valve was immediately verified to be in
about5:10p(n.m.ormally shut) position. The breaker had been
the proper
verified to be energized on a prior STA check (OST 1.48.3)
around 9:00 a.m. that morning.
The BIT bypass valve is used during post-LOCA RCS recirculation
to both the hot and cold leg piping about 14.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following
an accident.
Except for routine operability testing, the valve
remains shut during noma 1, nonaccident conditions.
The licensee immediately verified proper positioning of all
emergency power breakers and key valves. Augmented security
from a prior valve mispositioning event
measures resulting(reference:
on June 5-6, 1981
IE Inspection Report 50-334/
81-15 and IE Investigation Report No. 50-334/81-16) remain
in effect. The inspector reviewed completion of licensee
verification actions and independently verified proper position-
ing of selected ESF valves and breakers in the PAB between 9:30
p.m. and 11:30 p.m., August 5.
On August 5-6, 1981 the licensee investigated the circumstances
of the incident and determined that the breaker was probably
inadvertently bmped into the off position by construction workers
,
present in the area. During the dayshift on August 5, a crew
of four men were working in the East Cable Vault installing
firestop material in fire barrier penetrations. The carbon dioxide
fire suppression system for the cable vault had been placed in
[
manual operation, requiring a fire watch and logging of personnel
l
working in the area. Fire watch logs showed that, except for
l
personnel transiting the gnhle vault (not in proximity to the
l
breaker), only the above crew occupied the area. The work
I
crew was interviewed by the lf censee, the work activities of
I
the previous day reenacted, and the crew's equipment (found in
close proximity to the breaker) was observed. Although the work
!
crew members do not specifically recall bmping into breaker or
switchboard, the interviews and reenactment showed that the work
activities could have easily resulted in the breaker movement.
The licensee also found that only a slight force, such as may be
l
encountered in bumping the breaker, could cause the breaker handle
l
to move to the off position. Additionally, the breaker handle
l
is at about the hip-level of an average size man. The inspector
J
.
t
i
..s
-
.,
,
.-..
. _ - , . , .
_e.
--.
,e
- - -
.
-
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,
,
, .
-
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...
27
reviewed the results of the licensee's investigation with
the DLC Manager, Nuclear Operations, and other DLC staff
members on August 6, observec the work area and equipment
on August 5, 6, and 7 and considered the licensee's actions
<
acceptable and conclusions plausible.
On August 6,1981, the licensee had tem]orarily suspended
construction activities in the PAB, pencing the investigation
Based on the above conclusions, the licensee conducted training
for all construction workers assigned to BVPS-1, discussing
the incident and emphasizing tie need for extreme care in work
around operating equipment. Training was completed for all
workers onsite on the morning of August 6 and construction
activities permitted to resume in the afternoon. The DLC
Construction Division - Nuclear conducted repeat training
sessions on August 10 and 17 to accomodate absentees. The
inspector confimed administration of the training.
On August 7,1981 the inspector toured the East Cable Vault,
noting that the work crew's equipment (which is mounted on wheeled
dollies) was well away from the switchboard face and chained to a
stanchion to prevent inadvertant movement. Additionally, the
licensee had placed a rope barrier in front of the switchboard
to deter casual access. The inspector discussed these measures
and the incident with the original work crew members present
in the area on August 7 and confimed the infomation obtained
in the licensee discussions and the administration of training.
(6) During a comprehensive inspector review on August 10, 1981 of
recent DLC Licensee Event Reports (LERs), the inspector noted
that no LERs had been submitted by the licensee in accordance
with TS 6.9.1.0, Prompt Notification with Written Followup,
on two occasions in which the Technical Specification Limiting
Condition for Operations for TS 3.7.15, Penetration Fire
Barriers, had been exceeded. TS 6.9.1.8, Prompt Notification
with Written Followup, requires telephone and written notification
to NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during ". . . b, operation of the unit
or affected systems when any parameter or operation subject to
a limiting condition for operation is less conservative than the
least conservative aspect of the limiting condition for operation
established in the technical specifications."
TS 3.7.15, Penetration Fire Barriers, requires fire penetration
barriers protecting safety related areas to be functional at all
times. The associated Action Statement requires that with one
or more of the barriers nonfunctional, a continuous fire watch
on at least one side of the affected penetration shall be estab-
lished within one hour.
-
_ _ _
.
_.
--
_
__
.
-
-
_ __
--
._
_.
_ .
__
._~
_
.
. .
..
.
28
On two occasions, as discussed below, operation in excess of
-
the TS LC0 occurred with no corrective action im 'sented within
,.
,
the designated time frame.
-
During the inspection period June 1 - July 5,1981
--
(documented in IE Inspection Report No. 50-334/81-15)
'
the inspectors observed fire doors protecting safety
related areas in the Primary Auxiliary Building to be
,
open and unattended on three occasions without adequate
'
,;
measures either established er. implemented to assure that
,
7
a fire watch was in effect.
,
During the inspection period July 6 - August 2,1981
--
(documentedinIEInspectionReportNo. 50-334/91-18)
..
i%
the inspectors observed an electrical conduit penetration
,
fire barrier in the comon wall between the AE and DF
,
Emergency Switchgear Rooms to be only partially plugged
with fire retardant materials.
Each of the rooms comprises
a separate fire protection zone and each contained one
train of safety related electrical equipment. No fire
watch had been posted.
Upon notification by the inspectors, the licensee took imediate
corrective actions for each of the conditions described above.
-
These findings wer subsequently identified to the licensee as
Items of Noncompliance and documented in Notices of Violations
i
1
transmitted to the licensee with the respective inspection reports
6
above.
Upon noting the failure to submit the required LERs, the
u
inspectors immediately notified the DLC Chief Engineer who
stated that the failure to promptly submit the LERs had been
'
u
_
due to administrative oversight. The licensee promptly issued
~
LERs regarding the above findings on August 11, 1981. Based on
.
further discussion between the licensee, the inspectors, and
i
'
NRC:RI, it was determined that no enforcement action in addition
-
to that already initiated in the referenced Notices of Violation
J
was warranted.
..
,
~
(7) During review of Radioactive Waste D!scharge Authorization
.
-
(RWDA)-Liquid,No.01683,DischargeofSteamGeneratorDrain
'
Tank No. 7B on August 4,1981 (reference: paragraph 3.c(2)b of
this report) the inspector noted that the liquid waste effluent
-
l-
radiation monitor (RM-LW-104) had been declared out of service
'
just prior to the discharge. The monitor was considered in-
operable due to unacceptably high background radiation readings
resu?YM from plate-out of radioactive material on the detector
'
we% . TN inspector confirmed the licensee's acceptable imple-
s'
Wm .or, invironmental Technical Specification Action Statement
W ' for discharges with the monitor inoperable but identified
a u w n regarding a continuing problem with monitor operability.
r
-
% -
9
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--.- _.--_,---_ -.-
_..-.. - - -..... _, -.-.,.,--,..- _. _ .._..-..
-
.-
.-
. - - = - .
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- _ _ - -
}
..
...
.
29
RM-LW-104 is a process monitor in the liquid waste discharge
path which will automatically alam and teminate discharge
flow on detection of increased flowpath radiation. levels.
The licensee has experienced chronic difficulty in maintaining
detector well background radiation levels-low enough to pemit
detection of valid increases in process flow radiation.
In
order to provide short tem control of discharges, the licensee
has implemented Temporary Operating Procedure (TOP) 80-22 which
'
provides for calculation of a new High-High monitor trip setpoint
.
for each discharge of liquids having known isotopic radioactivity
levels of 1 E-5 to 4 E-4 uCi/cc and requires a maximum monitor
!
background reading of 1 E+4 counts per minute (CPM). When
background radiation levels exceed 1 E+4 CPM, the TOP requires
the detector to be removed and cleaned.
Through review of the Control Room radiation monitor setpoint
logs and operator logs, the inspector determined that the last
discharge via the RM-LW-104 flowpath occurred on July 29, 1981
^
and that the monitor had displayed background readings of
between 6 E+4 and 1 E+5 CPM from July 29 - August 4,1981.
During this period, the flowpath was isolated in accordance
with BVPS OM Section 1.17.4.W. Liquid Waste Discharge to Cooiing
Tower Blowdown, Issue 2, with double valve isolatinn e.d 10akoff,
effectively removing the discharge path and monitor from service
,
between actual discharge evolutions. The inspector was unable
to detemine why the detector had not been cleaned to reduce
,
background radiation levels during this period. The DLC Chief
Engineer advised the inspector that, although all regulatory
requirements for the discharge had been satisfied, licensee
management intended to have the monitor cleaned prior to use
without reliance upon the 2TS Action Statement. Operating
Manual Change Notice No.81-281 was issued on August 5,1981,
modifying BVPS OM Sections 1.17.4.0 and W to
quire reduction
of background radiation levels by flushing 9F wieaning upon
completion of each discharge in anticipation of the next ue.
The inspector had no further questions regarding the licensee's
short tem corrective actions.
Relative to the long term corrective actions, the licensee has
been consulting with manufacturers of quick-change disposable
detector wells which, unlike, the existing unit, could be easily
replaced when excessive background levels were reached. At the
close of this inspection, the" licensee was awaiting a manufac-
turer's detemination of detector compatibility with existing
monitor electronics. The acceptability and timliness of the
licensee's long tem corrective actions will remain unresolved
pending completion of licensee action and NRC:RI review.
(81-20-02).
/
.
.
.
-.
.
-
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...
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30
(8) The licensee uses a color coded calibration sticker system
to tag instrument drawers and racks, indicators, control
stations, etc. and to provide direct identification of:
i
Instrument /DeviceMark(Identification) Number;
--
Safety Related Instruments (Red Sticker) versus Non-Safety
--
Related Instraents (Blue Sticker),
i
l
Date of Last Calibration; and,
--
Due Date of Next Calibration.
--
As discussed in IE Inspection Report No. 50-334/81-18 (Inspector
Follow Item No. 81-18-02) and in paragraph 2 of this report,
the inspectors had identified deficiencies in infomation
included on the stickers for specific instruments but the actual
status of the instruments, not withstanding the deficient stickers,
was acceptable. During this inspection, additional instances
of discrepant calibration sticker information were identified
and resolution of instrument acceptability was continuing at
the end of the inspection.
The discrepancies are as follows:
Certain instruents are not included in the safety related
--
calibration program described in the BVPS Maintenance Manual,
Chapter 1, Section 0, Calibration Program, Revision 7,
Appendix IV. These instruments have been evaluated by the
Onsite Safety Comittee pursuant to 10CFR50.59 and have
been judged to be non-safety related.
Examples include
High Head Safety Injection Flow Instruments (flow to the
Hot Leg SI Header, te RCS Cold Legs, to Boron Injection
Tank), Steam Supply Pressures to the Steam Driven Auxiliary
Feedwater Pump, Containment Temperature Indicators,
l
Pressurizer Pressure Control Channels ~, and others.
In
'
such cases, the instrumentation or control functions either
provide a post-accident monitoring function or provide
direct control of NSSS parameters. During discussions
with the station Superintendent, Chief Engineer, Operating
Supervisor, and Maintenance Supervisor, the inspector
established that the licensee does not consider the equip-
ment to be safety related in that it does not provide a
direct function necessary for the prevention or mitigation
of an accident, e.g. the safety injection flow instruments
are not used to verify specific flow quantities during
emergency operations in accordance with BVPS CM Section
1.53.4, Emergency Operations, but are rather used
qualitatively to only verify that flow exists.
_ _ - _ _ _ - _ _
_
..
...
.
31
The licensee's non-safety related calibration program
frequencies are issued only as " general guidelines" in
BVPS MM Chapter 1 Section 0, and recalibration of " blue
sticker" or non-safety related instruments is only per-
formed when the channel or device displays anomalous
behavior, and then on an as-can basis with existing
resources. As a result, routine recalibrations at the
36-60 month intervals specified as guidelines by the
BVPS MM are not routinely perfomed (e.g. the last
calibration of Cold Leg Safety Injection Flow to RCS Loop
1 was perfomed November 15,1977). During this inspection,
'
Cold Leg Safety Injection Flow to RCS Loop 3 displayed
anomalous upscale indication and was declared Out of Service
on August 13, 1981; as of September 7,1981 this instrunent
remained Out of Service.
Its last calibration occurred
on September 24, 1977.
The inspector advised the licensee of the above concerns
during the inspection and at the exit meeting conducted
on September 9,1981. The acceptability of the licensee's
program for calibration of instruments including schedule
performance and categorization of safety related versus
non-safety related equipment will remain unresolved pending
additional review by NRC:RI.
(81-20-03).
The inspector also identified the following instruments
--
bearing red, safety related calibration stickers displaying
overdue dates for calibration.
-
NR-46 & -47, Power Range Nuclear Instrument Recorders
TI-RC-412A, -422A, RCS Loop Protection Delta-T Indicators
-
Source Range Nuclear Instrument Startup Rate Indicators
--
(Main Control Board)
LR-FW-498, Steam Generator Level Recorder
-
FR-MS-498-2, Main Steam Flow Recorder
-
PI-CC-100, Reactor Plant Component Cooling Water
-
Pressure Indicator
FI-BR-101B, "B" Degasifier Feed Flow Indicator
-
FR-GW-105, Gaseous Waste Decay Tank Flow Recorder
-
,
PI-RW-ll3A & B, Component Cooling Water Heat Exchanger
-
,
River Water Pressure Indicators
,
,
- - _ - - _ - - - - - - - - - - - - - -
- - - - _
_
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32
i
At the close of this inspection, review of completed
calibration procedures and data was in progress to confirm
the actual calibration status of these instruments. The
inspector also identified several other instruments with
erroneously completed calibration stickers that had current,
valid calibrations based on data review. The acceptability
of calibration status for the above instruments will remain
unresolved pending completion of the ongoing inspection.
(81-20-04).
(9) During routine review of Control Room logs on September 1,
1981, the inspector noted that a sample valve (SS-102) from the
CVCS mixed bed demineralizer effluent line had been found open
at about 5:00 a.m., September 1, draining water into the sample
sink drain to the North PAB sump. Operators had found the open
valve while investigating an abnomally high flow rate into the
sump. The valve was immediately shut.
On September 1-2, 1981, the inspector reviewed the circumstances
surrounding the open valve through discussions with the station
Reactor Control Chemist. The inspector established that a
routine sample had been drawn via SS-102 on the 3 p.m. - 11 p.m.
shift on August 31. The Chemistry Department personnel involved
could not clearly recall whether or not they had shut the valve
after the sample but, based on the arrangement of the sample
sink, the water stream from the valve should have been clearly
visible to the individuals as a direct indication of valve
position. The sample procedure in use required manipulation of
only SS-102
No other reason for the valve being open could be
established.
Through discuosions with the Reactor Control Chemist, the
inspectcr learned that the flow rate from SS-102 is on the
order of 200 ml/ minute (or about 3 gallons per hour) of
purified coolant and would not provide a significant contribu-
tion to sump inventory. The sump contents are processed via
the Liquid Radwaste System and the leakage presented no potential
for discharge to the environment or nomally occupied spaces.
No abnormal increases in general area or airborne radioactivity
levels were detected by the Radiation Monitoring System.
Based on the inconclusive review of this matter, the Reactor
Control Chemist issued an internal memorandum to all department
personnel advising them of the incident and emphasizing the
need to ensure positive isolation / restoration of sample valves
upon completion of sampling activities.
-- -- ---- ----
- - . - - - - - - - - - - - - - - - - - - - - . - . - - - - - - - - - - . - - - - - - - - - - - - - - . - - - _ - - - - . _ - - - - - . - - - - - - - - -
_
,
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33
(10) During review of surveillance test results discussed in
paragraph 3.c of this report, the inspector noted on August
20, 1981 that OST 1.44A.6, Chlorine Detection System and
Control Room Breathing Air Header Bottles Operability Check,
Revision 10, performed on August 19, 1981, required that the
chlorine detector electrolyte makeup frequency be calculated,
recorded on the shift turnover sheets for the Shift Supervisor,
Shift Foreman, and Nuclear Control Operator (reactor operator),
and that Step 3 of the procedure be signed by the above personnel
in acknowledgement of the completed actions. During review of
.
shift turnover sheets, the inspector found that only the shift
I
supervisor had made the required entry.
As discussed in paragraph 2 of this report (reference:
Inspector
Follow Item No. 80-30-08), the licensee has experienced chronic
failures of the Control Room chlorine detectors. The OST require-
ment for calculation and tracking of detector makeup frequency
was incorporated into Revision 10 of the procedure in July 1981
to provide more effective monitoring and servicing of the
units. As a result of the above finding the inspector addition-
ally reviewed records of test perfomantes for Revision 10 con-
l
ducted on July 22, August 5, and August 13, 1981. The inspector
found that, although the OSTs were each signed by the respective
Shift Supervisors, Shift Foremen and Nuclear Control Operators,
no turnover sheet entries had been made. A partial review of
operator logs for the dates above, however, found some entries
of makeup frequency in individual watch station logs vice the
i
shift turnover sheets.
On August 20,1981, the inspector advised the station Chief
l
Engineer and Operating Supervisor of the findings and expressed
'
concern that the individuals signing the OST had not complied
(
with the requirements of the procedure step. The licensee
representatives acknowledged the inspectors' concern and
initiated a review of the matter.
The inspector further noted that the licensee was maintaiaing
a shift log (Temporary Log, Series L8-1) for chlorine detector
parameters. Although this log provided infomation equivalent
to that required by the OST and therefore mitigated any tech-
nical or safety concerns, the operators appeared to consider
this an ex officio replacement for the turnover sheet entries.
The licensee's subsequent review of this matter, between
August 20 and September 4,1981, also established that, for
seven of the nine turnover sheet entries required, the operators
had made individual entries in their respective watch station
logs vice the turnover sheets, also as alternatives to the
requirement of the OST. None of the alternative ic]ging had
.
l
_
..
...
34
been carried over between shifts except the temporary
L8-1 log.
During the period July 22 - August 20, no
revisions or annotations were made to OST 1.44A.6 to
reflect the alternative logging methods in use.
On August 20, 1981, subsequent to the inspector's identifi-
cation of the logging discrepancies, the licensee issued
Operating Manual Change Notice (OMCN) No.81-306, deleting
the turnover sheet data requirements and replacing them
with a requirement to post the chlorine detector makeup
,
frequency on the Control Room status board. The inspector
periodically verified the currency of the status board entries
during the remainder of this inspection.
Failure to implement Step 3 of OST 1.44A.6 for the period
July 22 - August 20, 1981 and failure to maintain OST 1.44A.6
by appropriate revision (OMCN issuance) to reflect actual,
alternative practices is contrary to TS 6.1.8.c and constitutes
an item of noncompliance.
(81-20-05).
(11) During routine review of Control Room logs on b ;t.eber 3, 1981,
the inspector noted that OST 1.11.6, ECCS Flow Path and Valve
Position Check (LHSI Loop A), Revision 28, had been perfomed
~
on September 2, 1981. During that test, motor operated valve,
MOV-SI-863A, lA LHSI Pump Supply to Charging Pumps, presented
dual indication (both open ar.d closed indicating lights 111 uni-
nated on the main control board) when the valve was stroked full
open. Actual valve position had been confirmed locally by
operators.
The record copy of OST 1.11.6 had been annotated to indicate
the problem and signed off as complete. Maintenance Work Request
No. 812165 was issued on September 2 to adjust or repair the
defective indication. The valve position indicating circuits
were repaired, the applicable steps of OST 1.11.6 reperfomed,
and the valve returned to normal service on September 3,1981.
The valve is required to be operable by TS 3.5.2, ECCS Subsystems
0
(T-avg. equal to or greater than 350 F) and must be stroked
through at least one "omplete cycle of fu'.! travel monthly per
c
During discussions with the Shift Supervisor and Control Room
operators on September 3, the inspector was adv6d that the
defective valve position indication was not coi. . ared to render
the valve inoperable per TS 3.5.2, and therefore did not require
application of the TS 3.5.2 Action Statement requiring plant
..
.
.
_
_
_ _
_
_ _ _ . . _ . _
._.
_ - _
_..
_
_
...
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35
shutdown if the inoperable condition were not corrected
within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The licensee representatives considered
the valve and actuator, excepting the position indication,
to have performed its TS required function; the actual
position of the valve to be verifiable lo: ally or by indirect
means (corresponding changes in system parcmeters); and, the
valve's position indicators not to be a factor in establishing
the valve's operability per the above TS. That licensee
position was discussed with and confimed by the Station
Operating Supervisor and Chief Engineer on September 3-4,
1981.
TS Section 1.0, Definitions, SuNcction 1.6, Operable -
Operability, specifies the following:
"1.6
A system, subsystem, train component or device
shall be OPERABLE or have OPERABILITY when it is
capable of perfoming its specified function (s).
Implicit in this definition shall be the assumption
that all necessary attendant instrumentation, controls,
normal and emergency electric pcwer sources, cooling
or seal water, lubrication, or other auxiliary equipment
that are required for the systems, subsystem, train,
component, or device to perform its function (s) are
also capable of perfoming their safety related functions."
M0V-SI-863A is required to open during post-LOCA recirculation
to provide a water source from the containment sump to the
High Head Safety Injection (Centrifugal Charging) Pumps via
the LHSI Pumps following depletion of the RWST water inventory.
In this case, local verification of valve stem position may
not be feasible and indirect determination of valve position
by expected variation of system parameters relies, in part, on
use of instrumentation not subject to the safety related cali-
bration and maintenance program (reference: paragraph 3.d(8)
of this report). Therefore, position indication appears to
be subject to TS 3.5.2 as a contributor to the component's
ability to perfom its function.
Although " position indication" is not specifically listed in
TS 1.6 above, the inspector confirmed through discussions with
NRC:RI and NRC:NRR management that, for this and similar cases,
valve position indicators must be considered and that TS Action
Statements must be implemented when the indicators are inoperable
and reasonable, equivalent methods of determining actual valve
position are not available.
_
_
..
. . .
.
36
For the September 2-3 case, the licensee satisfied the
requirements of the TS 3.5.2 Action Statement even though
it was considered inapplicable. On September 3 and 8,1981
the inspector advised the station Operating Supervisor and
Chief Engineer of the above position, further stating that,
for such cases, wbcn position indicators remained inoperable
at the nomal conclusion of the surveillance test, the TS
action statemercs must be considered in effect. The licensee
representatives acknowledged the inspector's statements and
advised the inspector that future cases would be evaluated
on their respective rr.erits.
4.
In Office Review of Licensee Event Reports (LERs)
The inspector reviewed LERs submitted to the NRC:RI office to verify
that the details of the event were clearly reported, including the
accuracy of the description of cause and adequacy of corrective actions.
The inspector detemined whether further information was required from
the licensee, whether generic implications were indicated, and whether
the event warranted onsite followup. The following LERs were reviewed:
Report Number
Subject
LER 81-061/04L
Cooling Tower Clowdown Discharge Temperature
Exceeded Reporting Limit
LER 81-065/03L
Failure to Perfom Control Room Habitability
System Surveillance Test in Prescribed
Intc' val
LER 81-067/01P
Intentional Chlorination in Excess of ETS
Limits to Reduce Overpressure Condition
on Chlorine Evaporator
LER 81-066/03L
Train B Solid State Protection System Inoperable
During Plant Cooldown
LER 81-068/0lP
Fire Penetration Barriers Found Open
LER 81-069/04T
Tritium Discharge During Normai Operation
in Excess of ETS Reporting Requirement
LER 81-071/03L
- 2 Vital Battery Charger Inoperable Due to
Breaker Trip
LER 81 4.
'/03L
Inner Airlock Door Failed Leak Test
LER 81-073/03L
Control Room Chlorine Detectors Inoperable
LER 81-074/03L
Low Steam Line Pressure Bistable Inoperable
- Denotes those reports selected for onsite followup.
-
.
. _-
-
-
-
.
.. -
.
-
_ _ _
-
.
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...
37
LER 81-068/01P was submitted by the licensee in response to items of
noncompliance regarding fire penetration barriers. These findings
are discussed in detail in IE Inspection Reports Nos. 50-334/81-15
and 50-334/81-18.
No unacceptable conditions were identified.
5.
Onsite Licensee Event Followup
For those LERs selected for onsite followup (denoted by asterisks in
paragraph 4), the inspector verified that the reporting requirements
of the Technical Specifications and BVPS OM Section 1.48.9.D Miscel-
laneous Reports, had been met, that appropriate corrective action had
been taken or planned, that the event was reviewed by the licensee as
required by Technical Specifications and the BVPS-1 Station Adninistrative
Procedures Chapter 4 Plant Operations Group - Incident Reporting, and
that continued operation of the facility was conducted in accordance
with Technical Specifications and did not constitute an unreviewed
safety question as defined in 10 CFR 50.59(a)(2). The following findings
relate to the LERs reviewed onsite:
LER 81-71 and LER 81-59 - On June 15,1981, the No. 2 Station Battery
was placed on a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> equalizing charge. The battery charger breaker
tripped during the charge, apparently due to high ambient temperatures
in the general area and within the breaker enclosure. LER 81-59 was
issued on July 11, 1981, reporting this event and stipulating that
additional licensee action was planned to imp';.e the battery charger /
area ventilation system. Initial inspector followup was documented in
IE Inspection Report No. 50-334/81-18. A similar battery charger
breaker trip recurred on August 5,1981. On August 9, 19, 21, and
September 1,1981, the inspector reviewed the licensee's plans and
actions to prevent w currence.
The inspector found that a ventilation flow / velocity survey had been
perfomed during February 1981 in response to possible overheating
problems with Control Rod Drive panels and cubicle differential ventila-
tion pressures on the 713'ft. elevation of the service building (which
also contains the battery chargers). That survey identified several
deficiencies in flow balance and hardware operation which, when cor-
rected, resulted in nomal design flow rates and velocities for the
area. The licensee has also taken periodic area temperature surveys
to monitor ambient temperatures.
On August 20, 1981, the station Chief Engineer issued an Engineering
Memorandum to the Power Station Engineering Group requesting additional
inves'igation of long term corrective action.
Interim corrective action
c
cetinues to be placement of temporary fans near the battery chargers
during high ambient temperature conditions. The licensee's target date
for EM response is September 19, 1981. The inspector will continue to
follow the licensee's progress.
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I
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LER 81-61 - On July 8-9, 1981, during the previous inspection period
(IE Inspection Report No. 50-334/81-18), high outdoor and river water
temperatures resulted in cooling tower blowdown discharge temperatures
exceeding the reporting levels specified by Environmental Techrncal
Specification (ETS) 3.1.1.
During and after the period of high tempera-
tures, the inspector independently verified the measured temperatures,
times of the out of specification temperatures, and discussed licensee
intentions for possible extended periods of high temperature operation.
The licensee has periodically experienced discharge temperatures in
excess of the reporting limit but the temperatures do not routinely
exceed the four hour maximum duration specified by ETS 3.1.1.
6.
Review of TMI Action P'an Requirements
The inspector reviewed licensee implementation of TMI Action Plan Items
identified in NUREG 0737, Clarification of TMI Action Plan Requirements,
published November, 1980. The inspector reviewed the licensee's actions
with respect to the licensee letters identified below, the guidance
of NUREG 0737, and other applicable documents as referenced by NUREG 0737.
II.K.3.9 - Proportional Integral Derivative Controller Modification
On August 5 the inspector reviewed licensee implementation of
NSS vendor recommended modification to Pressurizer Power Operated
Relief Valve control circuits. Two out of three of the PORVs at
BVPS-1 have a derivative action in their respective control circuits.
j
This action provides for anticipatory opening of the PORVs on a
rapid pressure increase. The subject Action Plan Item required
deletion of this action from the control circuitry.
The NSS vendor recommended that the rate potentiometer on Pressurizer
control circuit PC-RC-444A be placed in the off position to accomplish
the above. On August 5,1981 the inspector directly observed the
appropriately positioned potentiometer. The inspector additionally
reviewed Maintenance Work Requcst No. 807148, issued and completed
October 17, 1980, subject: Set Rate and Reset Switches on PC-RC-444A
to the off position. During this review and discussions with the
l
DLC Instrument Engineer the inspector was infomed that the setting
of the reset switch to zero was an incorrect action identified prior
to startup from the Cycle I-II refueling outage. The incorrect
action was based on information promulgated by the Onsite Safety
Committee in Meeting Minutes No. BV-0SC-13780.
Inspector review
of those minutes and the attached NSS vendor correspondence could
not establish the reason for the erroneous direction provided by
either the committee or the Maintenance Work Request.
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The inspector additionally reviewed Loop Calibration Procedures
Nos. LCP-6-P445 and 444, Pressurizer Pressure Control Loop Cali-
brations. The inspector noted that LCP-6-P444 appeared to include
instructions for setting the rate signal potentiometer to 6 seconds
in lieu of zero as required by the NUREG Item. Discussions with
the DLC Instrument Engineer and Procedures Engineers confimed that
the procedures would be revised prior to their next use.
In the
interim, Jumper and Lifted Lead Tag No. 2632 was posted on the
rate potentiometer on August 5,1981 to ensure that the switch
is not reset prior to correction of the existing procedures. The
DLC Instrument Engineer advised the inspector that the Pressurizer
Pressure Control Circuits are not routinely recalibrated on an
established frequency Lut only when improper performance is observed.
Placement of the jumper and lifted lead tag will ensure that
attempted perfomance of the procedures during unanticipated trouble-
shooting prior to procedure revision will not result in misposition-
ing the comparator.
No unacceptable conditions were identified.
7.
Potential Deficiencies in Structural Designs
On April 16, 1981, DLC notified NRC:RI of apparent design deficiencies
in the structure of the BVPS Unit 2 Control Room. The Unit 2 Control
Room is a free standing extension of the Unit 1 Control Room / Service
Building complex. Unit.2 is under construction and the deficiencies
were reported under the provisions of 10CFR50.55(e) and the provisions
~
of the Unit 2 Construction Pemit. The deficiencies involved dis-
.
crepancies between the amount of structural / reinforcing steel specified
!
by design-calculations anc; that specified on drawings that had been used
for construction. As a result of tlese deficiencies, significt.nt modifi-
'
cation to the Unit 2 Control Rooin s'ructure is required. The deficiencies
j
appeared to be isolated to design calculations performed by a three-man
design team. These calculations were subsequently reviewed anct .avised
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to increase building reinforcement but, for reasons unknown, the construc-
tion drawings for the Unit 2 Control Room were nct revised prior t0
construction. A DLC written followup report to NRC regarding the Unit 2
deficiencies was issued on May 15, 1981.
On-August 18-21, 1981, a region-based inspector reviewed the licensee's
activities on Unit 2 relative to the above licensee report (reference:
IE Inspection No. 50-412/81-07). The inspector found that the licensee
had not fully reviewed the potential applicability of the Unit 2 design
2
deficiencies to Unit 1 structures designed and constructed by the same
'
\\rchitect Engineer (AE) and, possibly, the same design team. The
resident inspectors assigned to BVPS Unit 1 were advised of this matter
by the Unit 2 resident inspector on August 10, 1981 and continued NRC:RI
followup through DLC Nuclear. Division and station management.
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During August 18-28, 1981, the licensee's AE and Engineering Department
reviewed Vait 1 design work and~ established that the three-man design
team (above) had participated in the design of at least the Unit 1
Control Room, Containment, Main Steam Valve Room. Cable Vault and
Tunnel, and alternate intake structures. On August 28 and 31, 1981,
the DLC Manager of Nuclear Safety and Licensing advised the inspectors
that 62 calculations involving portions of the below structures had been
perfomed by the team, that an AE design review team would review the
calculations on an urgent basis, and that the design review would be
monitored by the licensee. On-August 28, 1981, the Manager, Nuclear-
Safety and Licensing, issued DLC Engineering Memorandum No. 30076
to the DLC Engineering and Construction Division, forwarding specific
requests for infomation relative to the acceptability of the Unit 1
structural designs.
On Septr
3,1981, the Manager, Nuclear Safety and Licensing,
advised
- inspector that AE review of the Unit 1 calculations was
as follows:
Containment - 55% completed
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Primary Auxiliary Building - 65% completed
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Cable Vault / Tunnel - 75% completed
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Fuel Building - 100% completed
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Control Room - 100% completed
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Service Building - 35% completed
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Safeguards Area - 100% completed
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The review entails comparison of original calculation results with
constry tion drawings; review of calculation input data, methodology,
continuity, and results; and, resolution of identified discrepancies.
The inspector was advised that minor discrepancies had been identified
and resolved with no adverse impact on the acceptability of the structures
based on new calculations or independent reviews. The licensee repre-
sentative further stated that the remainder of the design reviews would
be completed by about September 24, 1981. On September 7, 1981, the
inspector was provided with Stone & Webster Engineering Corporation
Letter No. DLS18247, R. C. Tappan to H. A. VanWassen, Structural
Calculation Review, dated September 3,1981, documenting the review
status infomation discussed above.
At the close of this inspection, the .: sign review effort was continuing.
The acceptability of the structural designs for BVPS-1 and the licensee's
review efforts will remain unresolved pending completion of the above
actions and review by NRC:RI.
(81-20-06).
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8.
Unusual Event - Gaseous Waste Decay Tank Leakage
About 12:00 p.m., Sunday, August 16, 1981, a Control Room operator
found the inservice Gaseous Waste (GW) Decay Tank (No. lA) and GW
Surge Tank pressures had decreased from about 6 psig to less than
1 psig over the previous 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, indicating leakage from the system.
The licensee declared an Unusual Event per Emergency Preparedness Plan
Implementing Procedures at 12:10 p.m., August 16. State, local, and
federal emergency management agencies were notified between 1:00 and
2:00 P S..
The Senior Resident Inspector was dif.; e.ched to the site
at 2:00 p.m. and followed licensee actions including:
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Review of GW System status, valve alignment, and trends of
principal system parameters;
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Licensee efforts to locate and isolate the source of leakage;
Status and indication of area and process radiation monitors
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.~ar evidence of leakage to plant spaces or release of
radioactivity to the environment;
The results of local airborne radia -tivity samples;
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Licensee estimates of potentially released radioactivity.
By about 3:30 p.m. the i ? ensee had isolated portions of the GW
system, effectively stopping the pressure decrease, and had begun
systematically repressuc. zing portions of the system to identify the
leakage A All radiation monitors and local samples showed no
detectable u:rborne radioactivity, including breathing zone samplers
worn by workers attemtping to diagnose the problem. Troubie shooting
continued through 12:00 a.m. with no further leakage identified, no
abnormal indication of airborne radioactivity in the plant spaces or
release paths, and no leakage path identified. The Unusual Event
status was teminated by the licensee at 12:00 a.m.
About 1:00 a.m., August 17, 1981, the licensee detemined that back-
leakage from the GW Decay and Surge Tank piping through the GW com-
pressors appeared to be pressurizing the Boron Recovery System de-
gasifiers, indicating backleakage through system check valves. The
suspected leakage path was isolated pending repairs. Concurrent with
the backleakage-induced pressure increase in the degasifiers, airborne
radiation levels in the Primary Auxiliary Building (PAB) increased and
weredetected by radiation monitors RM-VS-101A and RM-217A. The
increasing airborra radioactivity levels within the building were
subsequently isolated to the 1A Degasifier Cubicle and appeared to
result from a leak in the Degasifier heat exchanger (BR-E-12Al further
discussed in paragraph 8.a below). Airborne radioactivity levels
resulting from the degasifier heat exchanger leak reached levels of
about 1.5 E-8 uCi/cc (Rubiditsn) for a 20-30 minute period. Stack
radiation monitors si
'd a negligible increase in levels; no
regulatory limits were opproached. By about 4:00 a.m. the leakage
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has been isolated and PAB airborne radioactivity levels had returned
to nomal. .
About 2:30 a.m., August 17, a portable continuous air monitor on the
752' elevation of the PAB also alamed. Subsequent
followup by the
licensee established this airborne radioactivity to result from
unrelated Chemical and Volume Control System leakage discussed in
paragraph 8.b below.
Additional licenzee investigation on August 17, 1981 found another
potential leakige path from the GW Decay Tanks to the Primary Auxiliary
Buildino atmosphere. The system is equipped with Oxygen Analyzers to
detect possible explosive concentrations of oxygen mixing with the
hydrogen laden GW process stream. The Oxygen Analyzers have a "Zero"
meter reading test feature built-in the unit which permits .9troduction
of oxygen-free nitrogen gas into the unit for calibration of the instru-
cent zero point. With the "Zero" mode pushbutton on the front of the
unit depressed, the nitrogen bottle connection pipe was aligned to the
process flow stream but had no bottle or pipe cap installed. This
condition appears to have permitted a small volume of GW gas to leak
into the solid waste area of the PAB, however, portable and pemanent
radiation monitors nor grab samples detected any radioactivity above
background levels. Any such leakage was apparently so slight and suffi-
ciently diluted as to be undetectable.
Between August 17 and September 3,1981, the licensee took the following
additional actions:
The discharge check valves for both GW compressers were repaired;
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The inlet check valve to the 1A GW Decay Tank was repaired;
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The Oxygen Analyzer was leak tested, minor leaks repaired, and
the nitrogen test line capped; and
A leaking valve in the Oxygen Analyzer sample piping was replaced.
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At the close of the inspection a senior Nuclear Shift Supervisor assigned
to followup this incident had developed additional recomendations to
preclude recurrence.
In general, these involved modification of GW
system controls to prolong check valve life, improvement of Oxygen
Analyzer calibration procedure to ensure capping of test lines and
proper as-left alignment of the unit, and additional system monitoring
requirements for operator logs. These actions had not been fomally
submitted to licensee management for review or implementation. The
licensee's long tem actions will remain unresolved pending additonal
NRC:RI review during a subsequent inspection.
(81-20-07).
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a.
As discussed above, a Boron Recovery System Degasifier Heat
Exchanger developed a containment water leak during trouble-
shooting of the GW System problems on August 17, 1981. Addi-
tional, inspector review of heat exchanger repair activities is
discussed in paragraph 3.c(5) of this report. The leakage was
repaired but was similar in nature to a prior failure of this
type heat exchanger. At the exit meeting for this inspection,
the DLC Maintenance Supervisor advised the inspector that the
apparently recurrent failures had been referred to the licensee's
engineering staff for review and recomendations. The response
from the engineering staff is expected on October 9,1981. The
acceptability of the licensee's corrective and preventive actions
for the heat exchanger failures will remain unresolved pending
NRC:RI review.
(81-20-08).
b.
As also discussed above, leakage from the Chemical and Volume
Control System on August 17, 1981 resulted in slight increases
in PAB airborne radioactivity levels. Hydrogen (or nitrogen)
is added to the Volume Control Tank via one of two manifolds.
One is located outdoors on the East side of the PAB; the other
is located indoors on the 752' elevation of the PAB. Apparently
leaking check valves in the hydrogen addition piping pennitted
backleakage from the Volume Control Tank gas space to both of
the manifolds.
Initial indication of leakage was the higher
than normal airborne radioactivity levels. The source of the
leakage was not found until, on the day:hift, August 17, 1981,
personnel perfoming routine operations and maintenance of the
addition equipment in the PAB sustained hand and clothing con-
tamination as a result of the backleakage and were successfully
decontaminated by washing. Licensee surveys and samples at the
outdoor addition manifold confirmed that contamination had also
backleaked into the outdoor header.
On August 17, 1981, the inspector reviewed the results of seven
airborne radioactivity samples, local radiation and contamination
surveys at each location, and observed portions of the samples and
surveys conducted at the outdoor manifold. The samples and
surveys detected the presence of short lived (25-30 minute half-
life) radiogasses and daughter products. The two areas were
posted, isolated and access controlled. By August 19 all
radiation levels had returned to background levels. The defective
check valva were repaired. The inspector had no further questions
on this matter.
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9.
Errata.
IE Inspection Report No. 50-334/80-30, paragraph 5.d Onsite
Licensee Event Followup - LER 80-091, Low Boron Concentration in Boron
Injection Tank, was erroneously identified as Inspector Follow Item No.
80-30-09. The correct number for this item is 80-30-13.
10. Unresolved Items
Unresolved items are matters about which more information is required
to determine whether they are acceptable, items of noncompliance or
deviations.
5 unresolved items were identified and are discussed in
paragraphs 3.d(7), 3.d(8), 8, and 8a of this report.
11.
Exit Interview
Meetings were held with senior facility management periodically during
the course of this inspection to discuss the inspection scope and find-
ings. A summary of inspection findings was also provided to the licensee
at the conclusion of the report period.
,