IR 05000440/1987012
| ML20238D557 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 09/02/1987 |
| From: | Knop R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20238D534 | List: |
| References | |
| TASK-2.D.1, TASK-TM 50-440-87-12, NUDOCS 8709110250 | |
| Download: ML20238D557 (28) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-440/87012(DRP)
Docket No. 50-440 License No. NPF-58 Licensee:
Cleveland Electric Illuminating Company Post Office Box 5000 Cleveland, OH 44101 Facility Name:
Perry Nuclear Power Plant, Unit 1 Inspection At:
Perry Site, Perry, OH I
Inspection Conducted:
June 2 through August 12, 1987 Inspectors:
K. A. Connaughton G. F. O'Dwyer d'C W Approved By:
R.C. Knop,Chigf bgb e
Reactor Projects Section 18 Date
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Inspection Summary Inspection in June 2, 1987 through August 12, 1987 (Report No.
l 50-440/87012(DRP))
Areas Inspected:
Routine unannounced inspection by resident inspectors of i
previous inspection items, engineered safety features, operational safety, nonroutine events, Licensee Event Reports, startup testing, NRC Regional
Office requests, surveillance testing, maintenance activities, onsite review I
committee activities, and allegations.
I Results: Of the 11 areas inspected, 3 violations were identified in one area:
f (failure to provide appropriate drawings for the installation of MSIV pilot solenoid power supply wiring-Paragraph 5.a.(2)(a); failure to test MSIV
control circuitry in accordance with preoperational test procedures-Paragraph 5.a.(3); failure to maintain fire protection system manual containment isolation valves closed during plant operations-Paragraph 5.b.); and 2 violations were identified in a second area: (two examples of failures to take timely and/or effective corrective actions to prevent unplanned safety
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system actuations-Paragraph 6.; failure to perform independent verification of discharge path valve lineup prior to commencement of a liquid effluent batch release-Paragraph 6.).
The two violations involving the MSIV control i
circuitry were identified by review and followup of an NRC Augmented j
Investigation Team inspection concerning the June 17, 1987, MSIV closure /
reactor scram and documented in NRC Inspection Report 50-440/87014.
Additionally, four violations were identified in the second area; however,in h
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accordance with 10 CFR 2, Appendix C, Section V.A, a Notice of Violation was not issued (Operational Condition change with containment vaccum breaker open-Paragraph 6.;. Rod block not inserted for inoperable mode switch shutdown rod block interlock due to bent mode switch key-Paragraph 6.; Battery not declared inoperable with electrolyte temperature of 72 degrees F-Paragraph 6.;
inoperable APRM channel placed in tripped condition 5 minutes later than required-Paragraph 6). A meeting between NRC Region III and licensee inanagement was conducted on June 18, 1987, to review plant status and licensee performance. On June 29, 1987, the licensee entered a planned maintenance outage.
Following the outage, Test Condition 6 startup testing will resume.
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' DETAILS
'1.
Persons Contacted M.;R.'Edelman, Vice President, Nuclear Group
- A. Kaplan, Vice President, Nuclear Operations Division C. 'M. Shuster, Manager,. Nuclear Engineering Department (NED)
' *8. D.: Walrath, General Supervising Engineer, (NED)
- E. C. Willman, Senior Project Engineer, (NED)
. K. R. Pech, General Supervising Engineer (NED)
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'#*M. D. Lyster, Manager, Perry Plant Operations. Department (PP0D)
L D. J. Takas, General Supervisor, Maintenance Section (PP0D)
R. A.'Stratman, General Supervising Engineer, Operations Section, (PP0D)
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- L. R. Teichman, Supervisor, Maintenance Planning (PPOD)
- G. R. Anderson, Unit Lead Engineer (PP0D)
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F. R. Stead, Manager, Perry Plant Technical Department (PPTD)
W. R. Kanda, General Supervising Engineer, Technical Section (PPTO).
- S. F. Kensicki,; Technical Superintendent (PPTD)
L. L. Vanderhorst, Radiation Protection Section (PPTD)
- E. M. Buzzelli, General Supervising Engineer, Licensing and Compliance Section(PPTD)
- B. S. Ferrell, Operations Engineer, (PPTD)
- G. A. Dunn, Compliance Engineer, (PPTD)
- S. J, Wojton, General Supervising Engineer.(PPTD)
- R.A.Newkirk,GeneralSupervisingEngineer(PPTD)
E. Riley, Manager, Nuclear Quality Assurance Department (NQAD)
- V. K. Higaki, General Supervising Engineer (NQAD)
- W. E. Coleman, General Supervising Engineer.(NQAD)
- Denotes those attending the exit meeting held on August 12, 1987.
- Denotes those attending the June 18, 1987, management meeting.
2.-
Licensee Action on Previous Inspection Findings (92701)
a.
(Closed) Open Item (440/85022-35(DRP)):
Establish procedures for
' implementation of a leak reduction program for potential primary coolant sources outside containment (TMI Action Plan III.D.I.1).
The inspector reviewed Plant Administrative Procedure (PAP)-1111, i
" Primary Coolant Leakage Reduction for Systems Outside Containment,"
Revision 0, dated October 22, 1986. The subject PAP provided a
description of the leakage reduction program including respons-i ibilities for program implementation, leak detection and testing methodologies to be employed, a listing of systems included in the current program, and the bases for system selection. The ins also reviewed the following Periodic Test Instructions (PTIs)pector which
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were established to direct the accumulation and evaluation of system I
leakage data for systems included in the leak reduction program:
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PTI No.
Title GEN P0012
" Total Water Leakage Rate of Primary Coolant from Systems Outside Containment" GEN P0013
" Water Leakage Rates from Systems.0utside Containment Requiring Primary Coolant Leakage Reduction" GEN P0014
" Total Air Leakage of Primary Atmosphere from Closed Systems Outside Containment" GEN P0015
" Emergency Core Cooling Systems Header Drain Valves Seat Leakage Test" GEN P0016
" Reactor Core Isolation Cooling Auxiliary Steam Isolation Valve Seat Leakage Test" The inspector determined that the foregoing PAP and instructions
were consistent with licensee submittals dated May 29, 1985 and September 24, 1985. These submittals were previously reviewed by the NRC staff and found acceptable as documented in the Perry Safety Evaluation Report, Supplement 8, Section 11.5.
By letter dated June 28, 1987, prior to full power operation, the licensee submitted initial leakage data for the various systems and components included
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in the program to the NRC's Office of Nuclear Reactor Regulation.
b.
(Closed) Open Item (440/85078-02(DRP)):
Provide Perry-specific systems training for the Perry Plant Operations Department Manager prior to startup following the first refueling. During this inspection period, on June 19, 1987, the Perry Plant Operations Department Manager successfully completed.a Systems and Integrated Operations Training course offered by the Perry Training Department.
The course included four weeks of classroom lectures on Perry systems, and one week of simulator training on the Perry simulator.
(Closed) Unresolved Item (440/86018-01(DRP)):
Dix repar.cies between c.
Electrical Lineup Instructions, drawings, and brett.cr/ disconnect labeling. Licensee actions to resoive the identified dXerepancies. '
were reviewed and found a(ceptable in NRC Inspection Report 440/86025(DRP). At the thie of that inspection,:however, the
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licenset had yet to cbtain and install permanent ?abeling on aR electric 61 circuit breakers. 'This item remained coen pending replacement of temporary labels with permanent labels.
During this inspection period, the licensee informed the inspector that installation of permanent labeling had been completed. The inspecor varified by visual observation of selected divisional
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and rom-oivisional switchgear that the per;tanentlabeling had been installed a described by the licensee. The inspector has no further concerns regarding'this matter.
d.
(Closed) Violation (440/E7004-03(DRP)):
Inadequate operating daffastrative controlFresulting in inadvertent reactor nssel
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wat'er inventory decreases. The inspector reviewed the licensee's response letter dated May 20, 1987. The licensee's response indicated that the cause of the events associated with this violation resulted from a failure to implement established admin-istrative controls for valves left in an off-normal position.
The valve.with off-normal position and its associated boundary valves should have been tagged with white out-of-service tags in j
.accordance with Plant Administrative Procedure (PAP)-1401, " Safety j
Tagging." Corrective actions taken in response to this violation
included repair of feedwater isolation valve 1B21-F065B and the j
training of operations personnel concerning the procedural j
requirements for appropriately controlling system configuration.
j The. inspector verified during routine inspections of plant i
operating activities, that valve 1821-F065B had been restored to
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its normal operating status. The inspector verified by document
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review that operations personnel training was conducted between May 15 and June 16, 1987, to review the circumstances surrounding these events and operating administrative controls in place to preclude future similar events.
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(Closed).OpenItem(440/87004-04(DRP)): Corrective actions to
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prevent cable damage during removal of penetration sealing material.
l The inspector reviewed General Mechanical Instruction (G.'I)-0076, j
" Installation, Removal and Repair of Non-Foam Penetration Seals SF-60/SF-150," Revision 0; GMI-077, " Installation, Removal and
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Repair of Foam' Penetration Seals SF-20," Revision 0; and GMI-0083,
" Installation of Booted, Fiber Filled Configurations through Fire i
Barriers," Revision 0,. Each of these procedures incorporated a TestChangeNotice(TCN)-1which: -formalized the use of Form 7696,
" Penetration Seal Removal / Rework Request"; required the initial inspection of both faces of the penetration; restricted the use of sharp metal instruments; prohibited bracing off of certain equipment, and reqdred contacting Health Physics prior to removing any radiation or fire barriers. The inspector has no further concerns in this area.
f.
(Closed)OpenItem(440/87004-05(DRP)): Resolution of discrepancy I
between installed location of valve IP42-F650 and P&ID D-302-621 j
Revision L.
ECC Pump A Suction Line Drain Valve IP42-F650 was not j
in the location specified by Piping and Instrumentation Diagram (P&ID) D-302-621, Revision L. " Emergency Closed Cooling (ECC)
System." Drawing Change Notice (DCN) 1667 was issued by the
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licensee to correct the discrepancy. The inspector reviewed the j
updated copy of this drawing maintained in the control room and i
found that DCN 1667 was clearly referenced on the drawing. DCN 1667 was readily available in the control room and adequately specified the correct, as-built location of valve IP54-F650.
The inspector has no further concerns regarding this matter.
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I3.
Engineered Safety Feature (ESF) Walkdown (71730)
During.this inspection period, the inspector performed.a detailed walkdown of. train "A" and common. components of the Emergency Service Water (ESW) System. The system walkdown was conducted using Valve LineupInstruction'(VLI)-P45, Revision 2.
Prior to conducting the E
walkdown, the inspector verified VLI-P45 against controlled Piping and Instrumentation Diagrams (P& ids) for the ESW system.. No'significant discrepancies were identified as. a result of this verification..
During the system walkdown, the inspector directly observed equipment conditions to verify that hangers and supports were made up properly; appropriate levels of cleanliness were being maintained; piping-insulation, heaters, and air circulation systems were installed-and operational; with the exceptions noted below, valves in the system were installed in accordance with applicable P& ids and did not exhibit gross
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packing leakage, bent stems, missing'handwheels, or improper labeling; and, major system components were properly-labeled and exhibited.no leakage. The inspector. verified that instrumentation associated with the system was properly installed, functioning, and that significant process parameter values were consistent with normal expected values.. By direct visual observation or observation of remote position indication,.the inspector verified that valves in the system flow path were in the correct positions as required by VLI-P45; that where required, power was available to.the valves;' valves required to be locked in posisiton were locked; and, that pipe caps and blank flanges were installed as required.
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The inspector noted that a valve labeled as the "SLC EMG MAKEUP HOSE CONN ISOL," 1P45-F644 was not in the location specified by VLI-P45 and that the ESW Supply Header Vent Valves A & B (IP45-F648 and IP45-F645) were mislabeled in VLI-P45 as ESW Common Discharge Header vent valves. The inspector also found the following ESW valves not labeled:
F530A, F637A, F5446A, F636A, F551A, F639A, F638A, and F501A. The inspector notified the system engineer and was informed that resolution of these deficiencies would be sought. This matter is considered an open item (440/87012-01(DRP)).
In performing the system walkdown, the inspector took into account that the ESW system was in various modes of operation. The inspector verified that documentation required by licensee administrative procedures pertaining to temporary tagouts for maintenance was consistent with the system's declared status.
No violations or deviations were identified.
4.
Operational Safety Verification (71707)
l The inspectors observed control room operations, reviewed applicable j
logs, and conducted discussions with control room operators during this inspection period. The inspectors verified the operability of selected emergency systems, reviewed tag-out records and verified tracking of
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Limiting Conditions for Operation associated with affected components.
Tours of the intermediate, auxiliary, reactor, and turbine buildings were I
conducted to observe plant equipment conditions including potential fire 6 _
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hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for certain pieces of equipment in need of maintenance. The inspectors by observation and direct interview verified that the physical security plan was being implemented in accordance with the station security plan.
The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
These revic"e:s and observations were conducted to verify that facility operations were in conformance with the requirements established under j
technical specifications, 10 CFR, and administrate 1ve procedures.
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During this inspection period, on June 28, 1987, while operating at approximately 90% power, the Reactor Core Isolation Cooling (RCIC) system steamline automatically isolated due to a high steam flow signal from Leak Detection system flow transmitter IE31-N084A (Rosemont Model 1153).
At the time of the occurrence, the flow transmitter output signal was oscillating with a frequency of approximately 9 Hz and with sufficient amplitude to result in a false high steam flow isolation signal. The flow signal oscillations, which increased in amplitude with reactor power level, had been previously observed but had not previously resulted in RCIC steamline isolations.
The inspector was informed that the above described instrument behavior was the subject of General Electric Rapid Information Communication Service Information Letter (RICSIL) No.12 " Observed Increase in Process Instrument Noise", dated July 14, 1987. According to the RICSIL, oscillatory instrument output in the 6-10 Hz frequency range had been observed for other process variables which were also measured with Rosemont 1153 or 1154 differential pressure transmitters. The trans-mitters do not filter out these frequencies. At the close of this inspection, the licensee had initiated a design change to install fine mesh screens in the sensing lines associated with the affected RCIC steam flow transmitters in order to suppress the oscillations.
No violations or deviations were identified.
S.
Onsite Followup of Non-Routine Events at Operating Power Reactors (93702)
a.
June 17, 1987 MSIV Closure and Reactor Scram Following RPS Bus Deenergization - Findings Resulting From NRC Augmented Investigation Team Inspection Documented in NRC Inspection Report No. 50-440/87014 (1) Background / Event Description On June 17, 1987, the reactor scrammed following the deenergization of the "A" reactor protection system (RPS)
electrical bus and the unexpected closure of all four outboard main steam 1:;olation valves (MSIVs).
The RPS bus was deenergized due to faulty voltage sensing circuitry associated with the "A" RPS bus Equipment Protection Assembly (EPA) (supply circuit breaker). During scram recovery the
"A" kPS bus was reenergized using it's alternate electrical
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supply and upon bus reenergization, the outboard MSIVs reopened. All MSIVs were manually closed and the licensee maintained the reactor shutdown pending NRC and licensee evaluations of the event and completion of corrective actions identified as restraints to reactor restart.
An NRC Augmented Investigation Team (AIT) was formed and an onsite investigation was conducteo on June 17-20, 1987 to perform a fact-finding review of the event. The results of the AIT investigation were documented in NRC Inspection Report No. 50-440/87014.
Findings and/or issues identified based upon a review of NRC Inspection Report No. 50-440/87014 and followup inspection activities conducted prior to the close of this inspection are summarized in the following subparagraphs.
See NRC Inspection Report 50-440/87014 for details surrounding
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each finding / issue.
(2) NRC Inspection Report 50-440/87014, Paragraph 3., " Discussion of Design Error" (a) Failure to Transpose Design Drawing Revision General Electric drawing GE828E445CA, Revision 2, dated February 14, 1977, incorporated a design change which revised the MSIV pilot solenoid power supply wiring to provide independent power sources for the "A" and "B" pilot solenoids associated with each MSIV.
The design change was not correctly incorporated into electrical design drawings used for equipment installation. As a
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result, prior to the June 17, 1987 event, the as-built
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plant did not conform to the currently approved design and the design description included in the Perry Final Safety Analysis Report (fSAR).
Failure to provide appropriately revised installation drawings for the installation of the MSIV pilot solenoid power supply wiring in accordance with the current, approved design is contrary to 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures and Drawings" and is a Violation (50-440/87012-02(DRP)).
(b) Correction of the MSIV Wiring Error To correct the MSIV wiring error, the licensee issued Design Change Package (DCP)87-414 on June 20, 1987.
j During a planned maintenance outage which began on
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June 30, 1987, the licensee implemented DCP No.87-414
via Work Order No. 870005452. The inspector verified the forgoing by reviews of the subject DCP and Work i
Order. The design change installation and required i
retesting were completed and approved as of August 10, 1987.
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(3). NRC Inspection Report 50-440/87014, Paragraph 4.b.,
"Preoperational Test Program Review - Procedure Test Results" Preoperational testing of the.MSIV pilot solenoid wiring was conducted utilizing preoperational test procedure 1C71-P002.
As written, the test procedure did not reflect the as-built j
MSIV pilot solenoid wiring configuration and, therefore, could
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not be satisfactorily completed. Licensee personnel signed off test steps which were to have verified that the "A" pilot solenoids would remain energized following a deenergization of
the "B" RPS bus and that the'"B" pilot solenoids would. remain energized following deenergization of the "A" RPS bus.
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test steps were not performed as written, however, in that test
personnel did not observe the correct pilot solenoid status.
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lamps specified in the procedure due to a misunderstanding of'
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the labeling of the status lights.
Following deenergization
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of the "A" RPS bus, test personnel did not observe the status
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of the correct "A" solenoid status lamps on panel H13-P622.
Following the deenergization of the "B" RPS bus, test personnel
did not verify the status of the correct "B" solenoid status
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lamps on panel H13-P623.
Failure to perform preoperational i
testing in accordance with the approved test procedure is
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contrary to 10 CFR 50, Appendix B, Criterion XI, " Test Control" and is a Violation (50-440/87012-03(DRP)).
(4) NRC Inspection Report 50-440/87014, Paragraph 6., " Licensee Event Report Review - Potential Precursors" (a) Licensee' Review of Potential Precursors
Licensee Event Reports (LERs) 86044, 86050, 86071 and, 86072 documented six events involving deenergization of a single RPS bus. The inspectors requested the licensee to review each of these events to detennine what information was available to the operators concerning MSIV pilot solenoid status and if the MSIV miswiring could have been recognized based upon the available information. This
matter is considered an Open Item (440/87012-04(DRP)).
(b) Replacement of EPA Electronic Process Control Boards for the "B" RPS Bus Normal Power Supply LER 86-044 included a licensee commitment to replace all EPA electronic process control boards for both the RPS bus
"A" and "B" normal and alternate power supplies. As of the time of the AIT investigation, the licensee had not yet replaced the EPA electronic process control boards for the "B" RPS bus normal supply.
During this inspection, the inspector verified by document review that the licensee had replaced and satisfactorily tested the process control boards for "B" RPS bus normal supply EPAs 1C71S003B and IC71S003D via Work Order 870005401 which was completed on July 9, 1987.
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(c) Handling of Changes to Information Contained in LERs l
During the AIT review of LER 86044 the inspectors noted that the licensee reported that the storage shelf life
for the EPA process control boards was established by the i
vendor as three years.. During the AIT inspection, the inspectors noted that the shelf life of the boards had been extended to five years. While the licensee provide.d suitable justification for the shelf life extension, LER 86044 was not revised to reflect the shelf life change.
The inspectors were concerned that other, more substantive changes to information contained in LERs (e.g. commitments)
may not result in revisions to the LERs. This matter is considered an Open Item (440/87012-05(DRP)).
b.
Mispositioned Manual Containment Isolation Valves On July 3, 1987, at approximately 10:30 a.m., during the performance i
of Section 4.3 of System Operating Instruction (S01)-P54," Fire I
Protection System, " Revision 3, a plant operator found redundant manual primary containment isolation valves IP54-F726 and IP54-F727 i
(on a fire protection water supply line) open and unlocked when they
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should have been closed and locked. Licensee investigation found that.on June 21, 1987, while operations personnel were conducting a plant startup in accordance'with Integrated Operating Instruction i
(101)-1," Cold Startup, " Revision 3, an individual checked that the aforementioned valves were closed and locked as required by step 11.4.
Later that day however, because operations. personnel were still performing portions of 101-4," Shutdown," Revision 2 (as required by the previous plant shutdown), another individual opened i
the valves as required by step 4.5.32 of 101-4.
Inspector followup of this event included interviews with operating management personnel, review of 101 1 and 4 review of S0I-P54, review of Condition Report 87-323, review of draft Licensee Event j
Report (LER) 87048 and review of information provided by licensee i
personnel summarizing the documented history of the positions of
these valves beginning prior to startup June 21 and ending with licensee discovery on July 3, 1987.
Root cause analysis by the licensee determined that the valve mispositioning was the result of a procedural deficiency and j
personnel error. The opening of the valves per step 4.5.32 of
101-4 was not required to be completed prior to the closing of the valves per step 11.4 of 101-1. Other steps of 101-1 require,
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where appropriate, the completion of certain steps of 101-4 in i
order to prevent this type of problematic procedural overlapping.
I Operations personnel directing the concurrent performance of
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101-1 and 4 did not coordinate sufficiently to prevent this event.
Based upon available objective evidence, the valves remained open between June 21 and July 3,1987. The plant has operated from
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June 22 to July 1, 1987, in Operational Conditions 1, 2, and 3 (Power Operation, Startup and Hot Shutdown, respectively). This is contrary to Technical Specification 3.6.1.1.1 which requires, in part, that these valves be closed and secured in position in Operational Conditions 1, 2, and 3 and is a violation (440/87012-06(DRP)).
This is a repeat, in part, of violation.440/86011-03b(DRP) which indicated that the corrective actions to establish and maintain appropriate control of valves IP54-F726 and 1P54-F727 were not effective in preventing recurrence.
c.
Manual Scram Following Main Generator Bushing Failure On June 30, 1987, while operating at 100% power, elevated concentrations of hydrogen were detected in the main generator isophase bus ducting.
In accordance with operazing procedures, operating personnel began reducing reactor power to reduce generator load.
Subsequently, when the hydrogen concentration had increased to approximately 40% of the lower flammability limit, the turbine building and containment were evacuated and actions were initiated to remove the main generator from service.
Hydrogen concentration continued to increase and, approximately 4 minutes later operating personel manually scrammed the reactor fiom 28% power. All systems functioned par design following the scram. The fire brigade was dispatched to the turbine building when the hydrogen concentration reached the lower flammability limit approximately two and a half hours later. Within the following half hour, the concentration was reduced and maintained below the lower flammability limit by venting.
Licensee investigation disclosed that hydrogen used to cool the main generator had leaked into the isophase bus ducting due to the overheating and melting of sealing compound in the B phase inner neutral bushing. The overheating resulted from the presence of oil in the generator bushing cooling duct. The licensee performed inspections of all six generator bushings and found oil in the cooling duct of the B phase outer neutral bushing as well.
The B phase inner and outer neutral bushings were both replaced on July 2, 1987. To prevent recurrence, the licensee instituted periodic inspections of the generator bushing cooling ducts to detect
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blockage.
The foregoing information was developed by the inspector through:
visual examination of the failed generator bushing; interviews with
licensee operating and maintenance personnel; review of operating l
procedures and logs; and review of the licensee's post scram evaluation report 1-87-10.
Three violations were identified.
I 6.
Licensee Event Reports Followup (92700)
i Through direct observations, discussions with licensee personnel, and
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review of records, the following event reports were reviewed to determine
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that deportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specifications.
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LER 86014-IL Control Rod Drive HCUs Not Installed Per EQ Report Due to Lack of Information From Vendor LER 86021-LL Hydraulic Seal Failures Result in Inoperable Diesel Generator Building Ventilation Dampers LER 86025-1L CVDPS Design Deficiency Causes Containment Vacuum Relief Valves to Open LER 86056-LL RWCU System Design Problems Cause High Differential Flow Isolations-LER 86062-LL Conservative Design Setpoints Result in Actuations of the Drywell Vacuum Relief System LER 86067-LL Personnel Error Results in Redundant Reactivity Control System ARI and Reactor Scram l
LER 86068-LL RWCU System Design Problems Cause High Differential Flow Isolations LER 86073-LL Inadequate Procedure for Transfer of 4.16KV Bus Power Supply-Results in ESF Actuations LER 86079-LL Procedural Deficiency Causes Emergency Recirculation Actuation LER 86080-LL Failed Local Leak Rate Tests Result in Exceeding Allowable Containment Leakage LER 86082-LL
. Control Tachometer Prchlem Causes Diesel Generator Building Fan Autostart LER 86085-LL RWCU System Design Problems Cause High Differential Flow Isolations j
LER 86086-LL Rapid Adjustment of Feedwater Controller Results in Reactor Scram LER 86089-LL Failure to Review Electrical Diagrams Results in RCIC System Isolation LER 86092-LL Condenser Tube Leak Results in Technical Specification Required Reactor Shutdown LER 86093-LL Failure to Follow Procedure Results in Technical Specification 3.0.4 Violation
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t LER 86094-LL Bent Mode Switch Key.Results in Technical Specification l
Violation j
LER 86094-1L Bent Mode Switch Key Results in Technical Specification Violation LER 87001-LL RWCU System Design Problems Cause High Differential Flow Isolation LER 87002-LL Reactor Core Isolation Cooling System Isolation Due to I
Indeterminate Cause LER 87002-1L Inappropriate Restoration of Test Equipment Results in Reactor Core Isolation Cooling System Isolation LER 87003-LL Failure of Steam Supply Valve Results in Inoperable RCIC System LER 87003-1L Failure of Steam Supply Valve Results in Inoperable RCIC System LER 87004-LL Inadvertent Bumping of IRM Cables Causes Reactor
Protection System Actuation
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LER 87005-LL Deficient Surveillance Instruction Results in RPS Actuation LER 87007-LL RRCS Level Instrument Design Configuration Results in RRCS ARI and Reactor Scram LER 87008-LL Misunderstanding of Acceptance Criteria Results in Technical Specification Violation LER 87009-LL Degraded Solenoid Valves Result in Inoperable Diesel Generators LER 87010-LL Failure to Place Channel in Tripped Condition results in Tech Spec Violation LER 87011-LL Failure to Follow Procedure Causes Effluent Monitor Technical Specification Violation LER 87012-LL Inadvertent Actuation of Hot Surge Tank Level Switch Results in Reactor Scram LER 87013-LL RWCU High Differential Flow Isolations Caused by
Inaccuracies of Flow Detectors LER 87013-1L RWCU High Differential Flow Isolations Caused by Inaccuracies of Flow Detectors LER 87015-LL Deficient Test and Work Instructions Result in Unexpected CVDPS Isolations
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LER 87017-LL Personnel Error Results in Loss of Primary Containment Integrity LER 87018-LL Reactor Core Isolation Cooling System Isolations Due to Indeterminate Cause LER 87018-1L Inappropriate Restoration of Test Equipment Results in Reactor Core Isolation Cooling System Isolation LER 87019-LL Failure to Follow Procedure Results in RCIC System Isolation LER 87020-LL Inadvertent Bumping of Power Supply Breaker Results in Backup Hydrogen Purge Isolation l
LER 87034-LL Inappropriate Restoration of Test Equipment Results in Reactor Core Isolation Cooling System Isolation LER 87049-LL Deenergization of Reactor Protection System Bus During Performance of a Surveillance Instruction Results in Unexpected Shutdown Cooling System Isolation LERs 86056-LL, 86085-LL, 87001-LL, and 87013-LL and IL, all pertain to Reactor Water Cleanup (RWCU) system isolations due to high differential flow signals from leak detection system instrumentation.
Extensive investigations and evaluations conducted by the licensee have identified l
a number of contributing factors which resulted in leak detection system flow instrumentation inaccuracies under various RWCU system operating conditions.
Based upon these determinations, the licensee implemented several corrective actions to reduce the frequency of RWCU isolations.
These actions included: relocation of leak detection system flow measuring orifices; providing density compensation to flow instrument signals and; establishing procedural restrictions on system operation under plant conditions where flow instrument inaccuracy / instability had been most pronounced. Collectively, these actions were effective in
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reducing the frequency of RWCU system isolations due to high differential
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flow.
In order to further reduce, if not eliminate, future similar occurrences, the licensee has initiated a design change which will replace system flow control valves with valves which have more stable control characteristics over the entire range of system operation.
Due to required plant conditions, however, this modification has been scheduled to be implemented during the first refueling outage.
Additional inspector followup and review of licensee corrective actions regarding this matter will be conducted during future LER reviews.
LERs 86073-LL, 86079-LL, 87015-LL, and 87049-LL all involved unplanned engineered safety features actuations resulting from procedural
deficiencies involving deenergization of portions of the onsite electrical distribution system. The events described in these LERs which occurred on October 24, 1986, March 7 and 25, 1987 and
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July 4, 1987, all involved deenergization of a reactor protection system electrical bus. The resulting unplanned safety system actuations could
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have. been prevented by timely procedure reviews and identification
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of safety system actuations which.could be expected upon electrical j
system' distribution deenergization.
Failure to take timely and/or i
effective corrective actions to prevent repetitive occurrences such-as these is contrary to 10 CFR 50, Appendix B, Criterion XVI, and is a
an example of a violation (440/87012-07a(DRP)).
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LER 86093-LL concerned an event'which occurred'on December 29, 1986, when the license'e entered Operational Condition 1 while a containment vacuum breaker was open. Technical Specification 3.6.5.1 required that all.
containment vacuum breakers 'shall be. operable and closed whenever primary containment integrity was required. Associated technical specification action' statements permitted. continued plant operation with one containment vacuum breaker open for up to four hours. While this action statement ~ requirement was complied with, the fact that a mode change was made while the containment vacuum breaker was open was a violation of technical specification 3.0.4.
The cause of this' event was personnel error. Operating personnel failed to implement established administrative controls for tracking active
' technical specification ~1imiting conditions for operation upon receipt of an annunciator which indicated the vaccum breaker had cycled open.
i Licensee corrective actions included retraining of involved operating
personnel and revision of operating. procedures to specifically include verification of vaccum breaker position just prior to performing a. mode change.
Since the containment vacuum breakers functioned per design and action statement requirements applicable to Operational Condition 1 were not violated, this matter is not considered safety significant. However, performance of a mode change with a containment vacuum breaker open is a violation of technical specification 3.0.4 (440/87012<08(DRP)). This violation meets the tests of 10 CFR 2, Appendix C, Section V.
Consequent'ly, no Notice of Violation wi31 be issued and this matter is considered closed.
LERs 86094-LL and 86094-IL, describe an event which occurred on December 31, 1986, when the reactor mode switch was placed in the shutdown position following surveillance testifig which was performed while the mode switch was in the refuel position.
Due to a bent mode switch key, the reactor mode switch was not fully locked in the shutdown position and the 6ssociated control rod block trip function was not enabled. Operating personnel observed that the expected " Mode Switch in Shutdown Interlock Cleared" annunciator was received upon placing the
mode switch in the shutdown position. However, operating personnel failed to detect the absence of control rod block annunciation which should also
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have been received.
Technical specification 3.3.6 required that the trip function be operable whenever the reactor is in Operational Condition 3 (hot shutdown) or Operational Condition 4 (cold shutdown). Associated technical specification action requirements required that with the control rod
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block trip. function inoperable, a control rod block be manually inserted.
A minimum time interval for performing this action was not specified.
Throughout the time frame.over which the rod block interlock was inoperable (approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />) the reactor remained shut down with
- all rods fully inserted.
Corrective actions taken by the licensee upon discovery included immediate replacement of the mode switch key with a
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spare.
Subsequently, the licensee procured a nickel plated, brass mode j
switch key which was'.far less susceptible to bending during routine mode j
, switch manipulation.
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i Failure to insert a rod block with the mode switch shutdown position control. rod block trip function inoperable is a violation.of Technical Specification 3.3.6 (440/87012-09(DRP)).
This violation meets the tests
of 10 CFR 2, Appendix C, Section V, a.
Consequently, no Notice of
'j Violation will be issued and this matter is considered closed.
LERs 87002-LL and IL, 87018-LL and IL, 87019-LL, and 87034-LL all
-pertained to unplanned Reactor Core Isolation Cooling (RCIC) system isolations. Each of these events occurred during the performance.of
leak detection system surveillance testing and resulted from failures
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to install or remove required measuring and test equipment in accordance with the surveillance test procedure.
Installation of an ohmmeter used to monitor leak detection system RCIC isolation actuation relay contacts prior to placing the affected leak detection system instrument channel in bypass'resulted in one of these events. The remainder of the events resulted from a failure to remove the ohmmeter upon ' completion of-surveillance testing and unbypassing of the affected leak detection
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system instrument channel. These repeated procedural violations went
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unidentified by the licensee for a period of approximately five months,
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beginning in January 1987 through May 1987.
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Failure to. identify and correct deficient surveillance test procedure implementation in a timely manner resulted in these repetitive
occurrences, is contrary to 10 CFR 50, Appendix, B,' Criterion XVI, and is an~ example of a' violation (440/87012-07b(DRP)). This violation meets the tests of 10 CFR 2. Appendix C,Section V.
Consequently, no Notice of Violation will be issued and this matter is considered closed.
Regarding LER 87008-LL, on February 18, 1987, licensee surveillance testpersonnelmeasuSedtheDivision1,125Vbatterycellelectrolyte temperature to be 72 F.
Technicalspecification4.8.2.f.b.3,however, required that electrolyte temperature be greater than 72 F.
The individual performing the electrolyte temperature measurement did not recognize that technical specification acceptance criteria were not met.
The following day, licensee review of the surveillance test identified this discrepancy and a second set of battery cell temperature readings
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were taken and determined to be satisfactory. A faulty thermostat
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controllingthebatteryroomventilationsystemheaterwasigentifiedand replaced. Licensee evaluations determined that while the 72 temperature reading did not meet technical specification acceptance criteria, electrolyte temperature was not below the minimum for which the battery was sized. Other surveillance test parameters, including battery terminal voltage, float voltage, specific gravity, and electrolyte level
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were satisfactory. LThe event'is not considered safety significant, however,.failurgtomaintaindivisionalbatteryelectrolyte'temperatu'res
- greater than 72 - F is a violation of technical specification'3.8.2.1.a l
(440/87012-10(DRP)). This violation meets the test of 10 CFR 2, Appendix
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C,Section V.
Consequently, no Notice of Violation will be' issued and
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this matter is considered closed.
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Regarding LER 87010-LL, on February 28,1987 ' licensee operating personnel
' discovered that APRM flow biased simulated thermal power-high flow signal:
verification had last been conducted approximately 29-1/2 hours earlier.
Technical specifications required that this verification be performed at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, with a maximum extension of. 25% (30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> total). Upon expiration of the-surveillance" interval, technical j
specification 3.3.1, Action b required that at least one reactor j
protection system trip system be placed in the trip condition within
the following:1-hour.~
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Upon discovery 'the surveillance test was initiated immediately, however; l
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due to.a misinterpretation of test acceptance criteria, the test was
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considered unsatisfactory. One reactor protection system trip system
was placed in.the trip condition due to the apparently unsatisfactory j
surveillance. test results. This action occurred 5 minutes later than
required by technical specifications. Within the following three hours, the misunderstanding of test acceptance criteria was resolved, the surveillance was' completed satisfactorily, and the reactor protection system trip system was returned to service.
Failure to place the reactor protection system trip system in a tripped condition within the time specified in technical specification 3.3.1 Action b, is considered a violation (440/87012-11(DRP)). This violation meets the tests of 10 CFR 2, Appendix C, Section V, a.
Consequently, no Notice of Violation will be issued and this matter is considered closed.
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.Regarding LER 87011-LL, on October 21, 1986, a liquid radwaste discharge release from floor drain sample tank _G50-A004B to the emergency service water discharge was commenced. However, contrary to surveillance instruction G50-T25266, " Liquid Radwaste Release Permit," which was utilized to conduct the discharge, independent verification of the discharge path valve lineup was not performed. The surveillance instruction requirement implemented technical specification requirements contained in technical specification Table 3.3.7.9-1, Action 110-b concerning liquid radwaste discharge releases with the radwaste discharge radiation monitor inoperable.
Earlier, on October 19, 1986, the liquid radwaste discharge monitor had been declared inoperable.
This occurrence is repetitive of five similar occurrences between August 13 and 14, 1986.
Failure to independently verify the discharge path valve lineup prior to initiating a liquid radwaste discharge release is contrary to technical specification requirements contained in Technical Specification Table 3.3.7.9-l', Action 110-b and is considered aviolation-(440/870012-12(DRP)).
Three violations were identified for which Notice of Violation were
issued.
Four violations were identified for which Notices of Violation were not issued in accordance with 10 CFR 2, Appendix C, Paragraph V.
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S_tartup Test Witnessing and Observation (72302)
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. On June 1,1987, the inspector witnessed various portions of section 8.2, J
" Local Power Range Monitor (LPRM) Calibration with Process Computer," of
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Startup Test Instruction (STI)-C51-011, Revision 1, "LPRM Calibration,"
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and section 8.2, " Average Power Range Monitor (APRM) Calibration at High
Power," of S11-051-012, "APRM Calibration," Revision 2, and Surveillance
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Instruction (SVIs) C51-T5351, Revision 2, "LPRM Calibration" and j
C51-T0024, Revision 1, "APRM Calibration." The LPRM and APRM channels
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that were observed being calibrated were removed from and restored to
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service properly. The applicable Limiting Conditions for Operation (LC0)
I were complied with. Appropriate revisions of the procedures were in use l
by test crew members.
Crew staffing was adequate and sufficiently
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knowledgeable about testing. Test prerequisites and initial conditions were met.
Test equipment was calibrated in accordance with the licensee's administrative procedures. The tests were performed as required.
Crew actions were correct and timely and coordination and communications were adequate.
The inspector concurred with the licensee's preliminary analysis that the level 1 and 2 acceptance criteria for section 8.2 of STI-C51-012, and the level 2 acceptance criteria for section 8.2 of STI-C51-011 was met. The test data was accurate and properly collected by test personnel for final analysis. There was no level 1 acceptance criteria for section 8.2 of STI-C51-011.
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On June 2, 1987, the inspector witnessed various portions of section 8.1, " Core Thermal Power Determination," of Startup Test Instruction (STI)-C91-019, Revision 3, " Core Performance."
The current revision
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of the procedure was in use by all required test personnel.
All initial conditions and prerequisites were met or waived in accordance with procedural requirements.
Test data was provided by the process computer.
On June 2, 1987, the inspector witnessed various portions of section 8.7
" Dynamic System Test Case (DSTC) - Plant Sensor Checks," of Startup Test Instruction (STI)-C91-013 Revision 3 " Process Computer." The procedure was of the proper revision and was in use by all crew members. The test
crew was adequately staffed and knowledgeable. All test prerequisites
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and initial corditions were signed off in the procedure. Test equipment required by the procedure was calibrated and in service in accordance i
with the licensee's computer maintenance procedures. The test was performed as required by the procedure. Crew acticas appeared correct and timely and coordination between operations personnel and testing i
personnel was satisfactory. The inspector concurs with the licensee's preliminary determination that the control rod positions displayed on the Rod Display Module (RDM) on the P680 panel were the same as the positions stated by Process Computer Program, OD-7, "Present Control Rod Positions,"
'~' thereby verifying that OD-7 was operational and that the level 2 accep-tance criteria was satisfied for 0D-7.
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On June 3,1987, the inspector witnessed.various portions of section 8.10. " Dynamic System Test Case (DSTC) - Power Distribution and Thermal
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Limits Calculation," of Startup Test Instruction (STI)-C91-013, Revision
3, " Process Computer." The procedure.was current and in use by the appropriate test crew members. The test crew was adequately staffed and
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knowledgeable. All test prerequisites and initial corditions for this
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section were satisfied.
Permanent plant equipment was used to record
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test data.
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On June 4,,1987, the inspector witnessed various portions of section j
8.15, "DSTC -. 0D-12 Verification," of Startup Test Instruction
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(STI)-C91-013, Revision 3, " Process Computer." The procedure was of
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the proper. revision and was in use by the appropriate test crew members.
.The test crew was adequately staffed and knowledgeable. All test
. prerequisites.and initial conditions for this section were satisfied.
Permanent plant equipment was used to record test data. Testing was performed as required by the procedure. Test crew actions were correct and timely during the test performance.
Coordination and communications-l were sufficient. All data was collected for final analysis by the proper personnel. The inspector concurs with the test personnel's preliminary.
evaluation that program 00-12 " Isotopic Composition of In Core Fuel," '
was operational.
On' June 4, 1987, the inspector witnesse'd various portions of section 8.16. "DSTC - Computer Initialization Check on P1/0D-10-Phase I," of Startup Test Instruction (STI)-C91-013 Revision 3, " Process Computer."
The procedure was of the latest revision and was in use by appropriate
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test crew members. The test crew was adequately staffed and knowledgeable. All test prerequisites and initial conditions for this section were satisfied.
Permanent plant equipment was used to record test data. Testing was performed as required by the procedure. Test crew actions were correct and timely'during the test performance.
Coordination and communications were sufficient. All data was collected for final analysis by the proper personnel. The inspector concurs with the licensee's preliminary assessment that 00-15. " Computer Shutdown and Outage Recovery Monitor," properly functioned because the P1 edits before and after the dump had exposures sufficiently similar.
On June 4,1987, the inspector witnessed various portions of section 8.17. "DSTC - Computer Initialization Check on P1/0D-10-Phase II," of Startup. Test Instruction (STI)-C91-013, Revision 3, " Process Computer."
The procedure was current and in use by the appropriate test crew
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members. The test crew was adequately staffed and knowledgeable.
All test prerequisites and initial conditions for this section were satisfied. All test prerequisites and initial conditions were satisfied or waived in accordance with program requirements and reviewed as necessary.
Permanent plant equipment was used to record test data.
Testing was performed as required by the procedure. Test crew actions were correct and timely during the test performance.
Coordination and l
L communications were sufficient. Test personnel made a quick summary l-analysis to assure proper plant response.
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D The inspector concurs with the test personnel's preliminary evaluation that the 0D-15 program, " Computer Shutdown and Outage Recovery Monitor,"
functioned and properly updated the P1 program, " Periodic Core Evaluation".
The PI edit before and after the computer initialization were consistent.
On June 15, 1987, the inspector witnessed various portions of section 8.2, " Bypass Valve Capacity Measurement," of Startup Test Instruction (STI)-821-027, Revision 2, " Turbine Trip and Generator Load Rejection."
The test procedure was available and in use by the appropriate test crew members. The test crew was adequately-staffed and knowledgeable. All test prerequisites and initial conditions were satisfied or waived in accordance with program requirements and reviewed as necessary.
Permanent plant equipment was used to record test data.
Testing was performed as required by the procedure.
Test crew actions were correct and timely during the test performance.
Coordination and communications were sufficient. All data was collected for final analysis by the proper personnel.
On June 16, 1987, the inspector witnessed various portions of section 8.1, " Recirculation One Pump Trip and Restart," of Startup Test Instruction (STI)-B33-030A, Revision 2, " Recirculation One Pum'p Trip and Restart." The procedure was of the proper revision and was in use by the appropriate test crew members. The test crew was adequately staffed and knowledgeable. All test prerequisites and initial conditions for this section were satisfied.
Permanent plant equipment was used to record test data. Testing was performed as required by the procedure. Test crew actions were correct and timely during the test performance.
Coordination and communications were sufficient. All data was collected for final analysis by the proper personnel. The inspector observed that the level 1 acceptance criteria was met in the fact that the reactor did not scram following the A recirculation pump trip.
On June 24, 1987, the inspector witnessed various portions of section 8.2 " Pump Cavitation Interlock Test," of Startup Test Instruction (STI)-B33-30E, Revision 2, " Recirculation System Cavitation." The procedure was current and in use by the appropriate test crew members.
The test crew was adequately staffed and knowledgeable.
Permanent plant equipment was used to record test data.
Testing was performed as required by the procedure. Test crew actions were correct and timely during the test performance.
Coordination and communications were sufficient.
All data was collected for final analysis by the proper personnel. The inspector concurred with the licensee's preliminary evaluation that the recirculation pump transfer logic prevented operation in regions of potential cavitation and therefore satisfied the level 2 analysis acceptance criteria.
No violations or deviations were identified.
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Followup on Regional Requests (92701)
Main Steam I'olation Valve Circuitry s
During an NRC sponsored class, there was a' discussion about miswiring of Main Steam Isolation Valves (MSIVs) which caused a reactor scram following loss of.the "A" RPS bus (refer to Inspection Report 50-440/87014). A statement was made that a wiring problem, known in 1985, would cause closure of the MSIVs if an RPS bus failed.. Region III contacted the individual who made the statement and determined that the wiring problem identified in 1985 was in relation to the test solenoids and not the pilot' solenoids causing the scram in June 1987. This fact was also confirmed through conversations with General Electric engineers in San Jose, CA.
A review of the prints confirmed that the test solenoid circuitry was changed and was not a factor in the June 1987 scram.
This matter is closed.
9.
MonthlySurveillanceObservation(61726)
The inspector observed various portions of technical specification required surveillance testing on the Average Power Range Monitor (APRM)
channels and the Automatic Depressurization System Logic specified in Surveillance Instruction (SVI)-C51-T0024, "APRM Calibration,"' Revision 1 and SVI-B21-T1364-A, '.' ADS Channel A Logic System Functional Test,"
Revision 1.
The inspector verified that testing was performed in accordance with procedures, that test instrumentation was' calibrated, that limiting conditions for operation were met, that removal and restoration of the affected components were accomplished, that test results conformed with technical specifications and procedure requirements and were revfewed by personnel other than the individual directing the test, and that any deficiencies identifiei during the testing were properly reviewed and resolved by appropriate management persoweh No violations or deviations were identified.
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10. Monthly Maintenance Observation (62703)
Station maintenance activities of safety related systems and components
. listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards anti in conformance with technical specifications.
L The,following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were 1 41emented.
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Work requests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performance.
The following maintenance activities were observed / reviewed: rework of inboard and outboard Main Steam Isolation Valves (MSIVs) IB21-F022D and 1821-F028A, respectively, as documented by Work Orders (W.0.)87-731 and 87-732 and; work on the Fuel Handling Building Ventilation Exhaust Fan as documented by W.0. 86-15029, Revision 1.
l Following completion of maintenance on the MSIV's, the inspector verified that the MSIV's had been returned to service properly.
Upon discovery of damage to the shaft of the Fuel Handling Building Ventilation Exhaust Fan, licensee quality assurance personnel determined that the shaft could not be reinstalled as planned but had to be either reworked or repl?ced and therefore the work was suspended while the course of.iction wa'.
decided by engineering and management personnel.
No violations or deviations were identified.
11. Onsite Review Committee (40700)
The inspectors reviewed the minutes of the Plant Operations Review Committee (PORC) meetings No. 87-45 through 87-59, 87-61 through 87-162, and 87-164 through 87-186, conducted prior to and during the inspection period to verify conformance with PNPP procedures and regulatory requirements. These observations and examinations included PORC membership, quorum at PORC meetings, and PORC activities.
l No violations or deviations were identified.
12. Allegation Followup (99014)
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(Closed) Allegation RIII-87-A-0025:
Correction of Pressure Instrument Calibration Data for Local Variations in Gravity Allegation The licensee has been using international gravity units instead of local gravity units thereby failing to adjust for local gravity variation in mass weight testers and this is not properly being accounted for. Data sheets covering the calibration of these instruments are being falsified in that people know that these corrections should be made but they are not because of fear of job loss.
Followup j
Inspector evaluation of this allegation determined that the alleger was apparently referring to dead weight pressure standards purchased by the licensee in 1979 or 1980 with calibrations referenced to the standard acceleration of gravity (the assumed value of "g" at sea
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level. and '45 degree latitude - 980 6650 cm/sec)versuslocal acceleration of gravity. At the time, pressure gauges calibrated with the dead weight pressure standards did not have sufficient accuracy / precision to resolve the difference between instrument readings:resulting from the use of the two values for the i
i acceleration of gravity. Subsequently, over time, the licensee
- procured; increasingly accurate pressure gauges to be used in the field for.the calibration of installed plant instruments, capable of resolving the difference (approximately. 04%) in instrument
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readings resulting from the use of the local acceleration of l
gravity versus the standard acceleration'of gravity.
This matter was raised within.the licensee's instrumentation and-l controls organization approximately 2-1/2 weeks following NRC
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receipt of this allegation (prior to this inspection). The i
licensee's engineering ~ organization, in consultation with General Electric, evaluated this matter'and determined that correction for
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the difference between local and standard accelerations of gravity
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would not alter technical specification instrument setpoints or I
' allowable values based upon the extremely small magnitude of the
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error and the inherent limitations'on the accuracy of installed-plant instruments.
However, because this correction is an accepted practice in the-field of metrology in instrument applications where instrumentation is capable of resolving such differences, the 11censee opted, on'
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April 3, 1987, to begin using 980.2574 cm/sec las the value for i
gravitational acceleration in the calibration of instruments capable
of resolving the correction.
This value is consistent with that
contained in general tables for gravitational force at different f
latitudes developed by the U. S. Coast and Geographic Survey.
This value was recommended by the National Oceanic and Atmospheric Administration from data at the National Coast and Geographic
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Information Center.
j This allegation is censidered substantiated to the extent that the difference between local and standard gravitational acceleration had not been accounted for by the licensee prior to April 3,1987.
The inspector concurs, however, with the licensee's evaluation that the magnitude of the error introduced by the use of standard gravitational acceleration was sufficiently small in magnitude as to have no adverse impact on the ability of installed plant instrumentation to perform its intended safety functions.
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With respect to the portion of the allegation dealing with the falsification of calibration data sheets, the inspector determined I
that this notion was unfounded. The basis for this determination L
was that the convention of using standard gravitational acceleration
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in licensee instrument calibration activities prior to April 1987, was specified in calibration procedures used to generate calibration data sheets. Since calibration data sheets were generated in a technically acceptable manner, and as specified by procedure, falsification did not occur as alleged. The final porition of
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the allegation, that instrumentation and control technicians feared to raise this concern, could not be addressed directly because of the annonimity of the source of information. As stated above, once the concern was raised to the instrumentation and control supervisors, by the technicians in the department, the matter was addressed in an expeditious manner.
Further, the resident inspectors' routine dealings with the technicians have shown that the technicians freely discuss nuclear safety issues.
The data recorded on calibration data sheets prior to April 1987
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could, were it considered necessary or desirable, easily be l
corrected to account for the essentially negligible error introduced in the licensee's earlier calibration methodology.
This matter is considered closed.
l b.
(Closed) Allegation RIII 87-A-0034: Adjustment of Division III
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Diesel Governor During and Followirig Surveillance Testing Allegation The diesel responsible system engineer (RSE) has upon occasion reset
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the speed control knob on the Division III governor so that the engine will stabilize speed within allowed limits. This adjustment
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was made after the engine was shut down since the limit switches did
"i not reposition the governor within the correct limits. He has also had the engine's speed adjusted before shutting it down to ensure the speed setting would be correct.
Followup e
The inspector reviewed: Division III diesel generator controls, including the governor controls, as described in the Division III diesel generator vendor manual (Commercial Instruction and Parts Manual, General Electric-NED, WO72092, 2600KW Generator Set);
Division III diesel generator surveillance test procedures for technical specification required testing, and Division III diesel generator System Operating Instruction (501) E22B, Based on these reviews, the inspector determined the following:
(1)
If speed control adjustment occurred as alleged following diesel shutdown, it would ensure that the diesel would start
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and stabilize speed within allowable limits during a future start attempt. Diesel generator operability should not rely, however, upon manual adjustment of the speed control following a successful diesel run. As designed, the speed control should return to within standby readiness limits following a diesel shutdown. Additionally, the diesel generator design requires that if, during surveillance testing, a valid auto-start signal is received, governor control should automatically shift from the manual to the automatic mode with the speed control returning to within standby readiness limits.
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(2) While engine speed adjustment prior to diesel shutdown should not be required in order to assure that the speed setting will return to within standby readiness limits, engine speed adjustment is the means by which diesel generator load is varied during surveillance testing in which the diesel generator is paralled with the prefered power source.
Procedures covering diesel generator operation under such circumstances required that prior to diesel shutdown, the diesel generator was to be unloaded in 1000KW increments by manually lowering the governor speed setting and that typically, diesel shutdown occurred with diesel cenerator load very close to zero.
Under zero or close-to-zero load conditions, the governer speed setting should correspond to the standby readiness value.
In order to determine whether or not the governor speed control i
returned to within established standby readiness limits following surveillance testing, the inspector performed an unannounced inspection oi" a monthly diesel generai test conducted during this inspection period.
Prior to commencement of the test, the inspector observed the governor speed setting.
The inspector was then present during the diesel generator shutdown and directly observed the governor speed setting immediately following the rhutdown. The inspector observed that the governor speed setting corresponded to its pretest standby readiness value.
Based upon these observations, the inspector could not substantiate that there existed a need to make manual governor speed control adjustments following diesel shutdown to restore the diesel generator to standby readiness.
The inspector interviewed the RSE to determine whether or not he/she understood that diesel generator operability relied, in part, upon the ability of the governor speed setting to automatically readjust to within standby readiness limits following a diesel shutdown and upon receipt of an autostart signal during diesel operation with the governor in manual control. The RSE demonstrated a clear understanding of this fact and that manual diesel generator speed control adjustments were not to be relied upon to establish diesel generator governor standby readiness speed settings. The inspector noted, as further evidence of the RSE's understanding in this regard, that on October 20, 1986, the licensee reported pursuant to technical specification 4.8.1.1.2 that on September 11, 1986, a valid failure of the Division III diesel generator occurred due to a failure of the governor to properly reset the governor speed setting within required limits. The Division III diesel generator was declared inoperable following that failure. The diesel generator was nct declared operable until the governor preposition limit switch assembly was replaced and the diesel generator satisfactorily retested.
Finally, in response to direct questioning by the inspector, the RSE stated that he had never performed or relied upon manual governor speed adjustments during or following diesel surveillance testing
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to establish governor speed settings within established standby
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readiness limits.
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In summary, th'e inspector was unable to substantiate that portion of
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the allegation concerning adjustment of the governor speed setting
.following diesel shutdown. The fact that manual speed setting j
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adjustments were conducted during diesel generator surveillance tests was: substantiated and was simply the means by which diesel
. general load was varied during such testing. Whether~or not manual speed control adjustments were made prior to diesel shutoown for the express purpose of establishing governor speed setting within standby readiness limits, could not be substantiated.
This matter-is considered closed.
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No violations or deviations were identfied.
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13.
Plant Status Management Meeting (30702)
On June 18, 1987, NRC management met with CEI management in the-Regional l
Office to discuss the current status of the plant and recent events.
These meetings are being held on a periodic (initially monthly) basis.
'The meeting included discussions of:
the status of the plant; recent Licensee Event Reports (LERs); corrective actions taken or planned to be l
taken to preclude repetition; and, the schedule for future evaluations.
14. Open Inspection Items
- j Open inspection items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which
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involve some action on the part of the NRC or licensee or both. Open inspection items disclosed during the inspection are discussed in Paragraphs 3, 5.a.(4)(a), and 5.a.(4)(c).
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15, Violations For Which A " Notice of Violation" Will Not Be Issued The NRC uses the Notice of Violation as a standard method for formalizing the existence of a violation of a legally binding requirement. However, because the NRC wants to encourage and support licensee's initiatives for self-identification and correction of problems, the NRC will not generally issue a Notice of Violation for a violation that meets the tests of 10 CFR 2. Appendix C,Section V.A.
These tests are:
(1) the violation was identified by the licensee; (2) the violation would be categorized as Severity Level IV or V; (3) the violation was reported to the NRC, if required; (4) the violation will be corrected, including measures to prevent recurrence, within a reasonable time period; and (5)
it was not a violation that could reasonably be expected to have been
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prevented by the licensee's corrective action for a previous violation.
Violations of regulatory requirements identified during the inspection for which a Notice of Violation will not be issued are discussed in Paragraph 6,
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16. ExitInterviews(30703)
The inspectors met with the licensee representatives denoted in Paragraph I throughout the inspection period and on August 12, 1987. The inspector summarized the scope and results of the inspection and discussed the likely content of the inspection report.
The licensee did not indicate that any of the information disclosed during the inspection could be considered proprietary in nature.
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