IR 05000327/1993050
| ML20058P684 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 11/24/1993 |
| From: | Holland W, Kellogg P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058P644 | List: |
| References | |
| 50-327-93-50, 50-328-93-50, NUDOCS 9312270231 | |
| Download: ML20058P684 (28) | |
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UMITED STATES ooroN a
NUCLEAR REGULATORY COMMISSION p.
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REGION 11 j'.
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101 MARIETTA STREET. N.W., SUITE 2900
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- p ATLANTA, GEORGIA 303234199
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Report Nos.:
50-327/93-50 and 50-328/93-50 Licensee: Tennessee Valley Authority 6N 38A Lookout Place 1101 Market' Street Chattanooga, TN 37402-2801 i
Docket Nos.:
50-327 and 50-328 License Nos.: DPR-77 and DPR-79
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Facility Name:
Sequoyah' Units 1 and 2 Inspection Conducted:
October 1.1 through November 6, 1993 f4 Lead Inspector:
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W. E. Holland), Senior Re.sident Inspector Date Signed Inspectors:
S. M. Shaeffer, Resident Inspector S. E. Sparks, Project Engineer M. T. Widmann, Reactor Engineer J. T. Munday, Resident Inspector C. R. Ogle, Resident Inspector D. J Roberts, Resident Inspector G. P. Humphrey, Resident Inspector S. J. Cahill, Licensing Examiner R. D. Starkey, Resident Inspector L. Trocine, Resident Inspector
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M. A. Scott, Resident Inspector
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G. A. Sc ebli, Resident Ins ctor f/93 Approved by:
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t Paul
.Xellogg(gieM Mion 4A.-
Date' Signed Divi io W uor Projects SUMMARY Scope:
Routine resident inspection was conducted on site in the areas of plant operations, plant maintenance, plant surveillance, evaluation.of licensee
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self-assessment capability, licensee event report closeout, and followup on previous inspection findings. During the performance of this inspection, the resident inspectors conducted several reviews of the licensee's backshift or weekend operations.
In addition, inspectors continued 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> monitoring of
Unit.2 restart activities through the inspection period.
9312270231 931203
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PDR ADOCK 05000327 G
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j Results:
In the area of Operations, a violation was identified for failure to operate Unit 2 in MODE 3 as required by SSP-12.1, CONDUCT OF OPERATIONS and TS 3.7.1.2-
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(paragraph'3.a.(1)).
l In the area of Operations, good operations group performance was noted in I
response to a letdown isolation event (paragraph 3.a.(2)).
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i In the area of Plant Support, a non-cited violation was identified for' failure l
to follow the procedural requirements of SSP-12.15, FIRE PROTECTION PLAN and
0-PI-FPU-000.001.W, OPERATIONS FIRE PROTECTION UNIT WEEKLY INSPECTION j
(paragraph 3.b.(1)).
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In the area of Operations, a configuration control problem associated with
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operator inattention to detail was identified regarding an ERCW pump breaker-
spring charging motor switch being left in the off position (paragraph
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3.b.(2)).
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In the area of Operations, a violation was identified for failure to follow
the requirements of SSP-12.3 (paragraph 3.c.(2)).
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In the area of Operations, specific observations of control room operator Li performance identified improvements _in communications during testing-l activities, identification of equipment problems, and a willing attitude not
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to " live" with degraded equipment. However, other areas were also observed.
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(paragraph 3.g),
i In the area of Maintenance, a weakness was identified regarding the incorrect
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assembly of two air operated valves, one of which contributed to a Unit 2
letdown isolation event.
In addition, material condition problems were noted
which adversely affected air regulator performance during the same event.
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L In the area of Operations, an example of continuing communication problems -
between operations and chemistry personnel was identified regarding diesel
fuel sampling (paragraph-4.b).
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In the area of Operations, a review concluded that the Sequoyah ISEG was providing plant management with good assessment findings in a manner which
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clearly identified weaknesses in programs or processes. Review quality'was considered to be a strength (paragraph 6.a).
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REPORT DETAILS 1.
Persons Contacted Licensee Employees R. Fenech, Site Vice President
- K. Powers, Plant Manager
- J. Baumstark, Operations Manager L. Bryant, Maintenance Manager M. Burzynski, Nuclear Engineering Manager
- M. Cooper, Maintenance Program Manager
- D. Driscoll, Site Quality Assurance Manager C. Kent, Chemistry and Radiological Control Manager
- D. Lundy, Technical Support Manager
- M. Palmer, Radiation Protection Manager
- R. Rausch, Site Planning and Scheduling Manager
- G. Rich, Chemistry Manrger
- J. Symonds, Acting Modifications Manager
- R. Shell, Site Licensing Manager J. Smith, Regulatory Licensing Manager
- R. Thompson, Compliance Licensing Manager
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J. Ward, Engineering and Modifications Manager N. Welch, Operations Superintendent
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NRC Employees R. Crlenjak, Chief, DRP Branch 4 P. Kellogg, Chief, DRP Section 4A
- Attended exit interview.
Other licensee employees contacted included control room operators, shift technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used in this report are listed in the last paragraph.
2.
Plant Status Unit I began the inspection period in MODE 5 (day 188 of the Cycle 6 refueling outage). At the end of the inspection period Unit I remained in MODE 5 with efforts continuing to correct restart deficiencies.
Unit 2 began the inspection period in MODE 5 (Day 223 of a forced outage). Unit 2 commenced heatup in accordance with procedures and increased RCS temperature above 200 degrees F (MODE 4) on October 11, 1993. The unit increased temperature above 350 degrees F (MODE 3) on October 13, 1993. All required.;esting was completed in MODE 3 and the
Unit 2 was taken critical (MODE 2) on October 19, 1993. The unit I
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f returned to power operation on October 21, 1993 and increased power to the 30% hold point. On October 22, with Unit 2 at 30% power, one of the letdown isolation valves failed and the valve went shut. Operators tried to establish the excess letdown flowpath. However, one of the excess letdown flowpath valves would not open. Over the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, operators reduced power and shutdown the reactor to MODE 3.
This event is further discussed in paragraph 3.a (2). After corrective actions were completed for the letdown isolation valve issues, the unit returned to power operation on October 27, 1993, and increased power to
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approximately 38% over the next two days. Another problem was identified with the main generator voltage regulation circuitry. The
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main turbine generator was taken off line to work this problem on October 30, 1993. The reactor was maintained at 20% power on steam dumps during the generator voltage regulator repair period. After the main generator voltage regulator problem was corrected, Unit 2 returned to power operation on October 31, 1993, and reached full power on November 5, 1993. The unit operated at power for the remainder of the inspection period.
However, at the end of the period, power had been reduced to approximately 40% due to identification of additional
generator voltage regulator problems.
3.
Operational Safety Verification (71707)
a.
Daily Inspections
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The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator adherence to approved procedures, TS, and LCOs; examination of panels containing instrumentation and other reactor protection system elements to determine that required channels are operable; and review of control room operator logs, operating orders, plant deviation reports, tagout logs, temporary modification logs, and tags on components to verify compliance with approved procedures.
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The inspectors also routinely accompanied plant management on plant tours and observed the effectiveness of management's influence on activities being performed by plant personnel.
(1)
On October 14, 1993 at approximately 6:55 a.m. the inspectors noticed, during a control room tour of Unit 2, that both motor driven auxiliary feedwater pump control
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switches were in the pull-to-lock position. Unit 2 had entered MODE 3 operation on October 13, 1993. The
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inspectors informed licensee operations management of this observation during the shift turnover meeting which started at 7:00 a.m.
Operations management interviewed the control room operators on shift at the time of the NRC observation and also reviewed the TSC computer printouts to verify the inspectors' observation. The licensee determined that hoth motor driven AFW pump hand switches had been placed in the pull-to-lock position at approximately 6:26 a.m. on
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I October 14, 1993. The pumps had been restarted from the control room at approximately 7:10 a.m. on October 14, 1993.
Plac4ng the motor driven AFW pump hand switches in pull-to-lock while Unit 2 was in MODE 3 put the unit in TS LCO
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3.7.1.2, ACTION b.
The licensee reviewed the condition with operations personnel on duty at the time of the event. That review concluded that the CR0 had inadvertently placed the pump handswitches in pull-to-lock when securing the pumps from operation at approximately 6:26 a.m.
The 0ATC restarted the pumps at approximately 7:10 a.m. the same morning to maintain desired SG 1evels.
Both operators were
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not attentive to the requirement to have the pumps OPERABLE
in MODE 3 at the time of the event. The event review concluded that the root cause of the hand switches being in the pull-to-lock position was personnel error due to inadequate self-checking. The inspectors reviewed the licensee's event review and basically agreed with the conclusion. However, the inspectors also noted this event is another example of operators' lack of safety sensitivity to plant conditions.
The inspectors reviewed SSP-12.1, CONDUCT OF OPERATIONS, Rev. 6.
Paragraph 3.1.2.J.1 of SSP-12.1 assigns, in part, shared responsibilities to the Unit Operator and the Operator at the Controls to operate the unit in' compliance with the operating license and Technical Specificathos.
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Failure to operate the unit as required by Technical Specifications is identified as a violation (VIO 328/93-50-01), Failure to operate Unit 2 in MODE 3 as required by SSP 12.1.
The licensee's investigation, response, and corrective actions to this issue were satisfactory; thus, no response to this violation is required.
(2)
On October 22, 1993, the inspectors monitored licensee response to a Unit 2 event involving loss of the normal letdown flowpath and a second failure of an excess letdown valve to open. Just prior to the event, the unit was holding at approximately 30% reactor power for repair activities and chemistry cleanup of the secondary inventory.
Pressurizer level was at approximately 34%. The transient began at approximately 2:50 p.m. when the unit experienced a failure of letdown valve 2-FCV-62-70. Operators initially became aware of the problem via a high letdown temperature alarm and immediately identified that the 62-70 valve had
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failed to the closed position. The valve could not be reopened from the control room.
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Operators then attempted to align the excess letdown i
flowpath in accordance with 2-50-62-1, CHEMICAL AND VOLUME
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CONTROL SYSTEM. This evolution involved the opening of 2-FCV-62-54, 55, and 56. However, excess letdown valve 2-FCV-
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62-54 failed to open. This resulted in a total loss of l
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-letdown capability for the unit.
Normal charging though-the RCP seals was being provided-by one running CCP.
In-this configuration, the pressurizer level immediately began-increasing at a rate estimated by the inspectors of 1% every 3 minutes. Both of the failed valves were air operated to-open, spring to close, gate valves. Neither of the valves were containment isolation valves.
The licensee immediately recognizsd the potential consequences of the uncontrolled RCS. level increase and began analyzing options to correct-the problem. Normal and'-
abnormal operating instructions were referenced; however, the failure of all letdown paths was not encompassed by.
existing procedures. Operators began taking. actions to:
delay the rise in pressurizer' level' until the unit could be shutdown or letdown reestablished. These actions included.
reducing the seal flow to the RCPs to approximately-6 gpm per pump. At approximately 3:30-p.m., the licensee was formulating plans to attempt local operation of either 62-70 or 62-54. valves. The 62-70 valve is located in the Unit 2 containment, # 2 accumulator room (relatively low dose area); however, the 62-54 is located in the Unit 2 containment, inside the polar crane wall and is not accessible during power operation due to radiological concerns.. The licensee decided to initiate actions to attempt an air supply jumper to the 62-70 valve..
By 3:54 p.m., pressurizer level had increased to approximately 58%. Shortly after, personnel working on 62-70 reported to the control room that the air diaphragm on the valve operator appeared to be ruptured and the air.
supply jumper would likely not be successful. With.this information, operations management decided to initiate a load decrease to 20% reactor power. This was performed'in'
accordance with G01-3, PLANT. SHUTDOWN FROM MINIMUM LOAD TO COLD SHUTDOWN. During the load decrease, additional actions were taken' to delay the pressurizer level increase which included the opening of pressurizer vapor space and RCS sample lines.
At 4:20 p.m., 20% reactor power was' attained with no secondary perturbations.
Pressurizer level was now at approximately 66% and continuing to rise, despite the
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licensee's efforts to delay RCS fill.. Throughout the above events, operators repeatedly attempted to reopen 62-70 or-62-54 with no success.
Between 4:30. p.m. and 5:30 p.m., the licensee held the' unit at 20% reactor power and continued attempts to manually open 62-70 via air jumpers and mechanical jacking of the. valve.
The 62-70 va?ve is located in a confined location which affected the licensee's ability to work on opening the
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valve. Licensee management indicated that their strategy was to continue attempts to open 62-70 until the pressurizer level reached 80%.
If the letdown path was not reestablished by that time, a unit shutdown to MODE 2 and 3-was to begin.
It should be noted that a high pressurizer level reactor trip signal would occur automatically at 92%.
At 5:34 p.m., pressurizer level reached 80% and efforts to restore the letdown path were unsuccessful. At 5:40 p.m.,.
operators initiated a unit shutdown from 20% reactor power at 1% load decrease per minute. At 5:48 p.m. the main turbine was manually tripped and the two motor driven AFW pumps were manually started. At this time, pressurizer level had increased to 84%. As a result of the power reduction to 1% reactor power, by 5:53 p.m., the pressurizer level had decreased to 82% due to the Tave reduction and resulting RCS shrinkage.
Work was initiated at this power
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level to troubleshoot valve 62-54, the excess letdown valve, in addition to the effort to open valve 62-70. Due to the power reduction, pressurizer level stabilized at approximately 82%. The licensee continued the shutdown and the reactor was taken subcritical (MODE 3) at 6:31 p.m with RCS Tave at 541 degrees F.
At 7:26 p.m., pressurizer level had risen to 86%. Operators were continuing to borate the RCS to maintain adequate shutdown margin and were completing the insertion of all control and shutdown rod banks per procedure.
At 7:33 p.m., maintenance personnel informed the control room that an air jumper had been successfully installed around what appeared to be a failed regulator for valve 62-54. The valve was then opened and excess letdown flow was established. The highest pressurizer level attained was approximately 88%. The excess letdown flowpath was then used to lower pressurizer level to approximately 24%, which is a normal level for MODE 3 plant conditions. Work was then accomplished to repair valve 62-70. After the repair was complete, the normal letdown flowpath was reestablished and the excess letdown flowpath was secured. The licensee then replaced the regulator and diaphragm for valve 62-54.
Inspection activities related to the specific failure mechanisms of the letdown valves are discussed in paragraph 4.a.
The inspectors concluded that the operators performance in evaluating the plant valve / operational problems and formulating a success path with the known valve failures was good. Communications between operations and maintenance staff / management was also noted to be good during the repeated attempts to open the letdown valves.
In addition, the inspectors considered the decision on the part of
Operations Management not to allow personnel entry inside the polar crane wall to work on the 62-54 valve given the unit condition and radiological concerns was proper.
b.
Weekly Inspections The inspectors conducted weekly inspections in the following areas: operability verification of selected ESF systems by valve alignment, breaker positions, condition of equipment or component,
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and operability of instrumentation and support items essential to I
system actuation or performance. Plant tours were conducted which included observation of general plant / equipment conditions, fire protection and preventative measures, control of activities in progress, radiation protection controls, missile hazards, and plant housekeeping conditions / cleanliness.
(1)
During a walkdown of the turbine building on October 14, 1993, with licensee personnel, the inspector identified four TFL permits which had expired on October 1, 1993, and which had not been issued extensions by plant management. These permits, TFL-93-0076, TFL-93-0077, TFL-93-0080, and TFL-93-0084, were all located in non-safety related areas of both the Unit I and Unit 2 sides of the turbire building.
In addition to being expired, two of the permits had temporary fire loads added on an attachment sheet between October I and October 14, 1993.
The inspector reviewed Site Standard Practice (SSP) 12.15, FIRE PROTECTION PLAN, Revision 2, the procedure which implements the licensee's fire protection program at Sequoyah. Appendix E, Section 1.A.11 of that procedure requires.that TFL permits do not exceed a 3-month period and that any extensions be approved by the Plant Manager.
Additionally, Section 1.A.8 of Appendix E to SSP 12.15 requires that the Operations Fire Protection Foreman perform and docurent weekly inspections to determine the odequacy of the TFL controls.
Periodic Instruction 0-PI-FPU-00t,03.W, OPERATIONS FIRE PROTECTION UNIT WEEKLY INSPECTION, Ruision 1, provides specific guidance on how to conduct and document this weekly inspection.
It specifies that deficiencies will be identified and documented, and that corrective actions will be promptly pursued.
Finally, Section 1.A.10.f of
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Appendix E to SSP 12.15 requires the supervisor / foreman directly responsible for the work in the plant shall inspect the transient fire load each workday to ensure it is i
properly controlled and that the requirements of the permit are met.
The inspector's finding regarding the four expired TFL permits and his discussions with plant personnel responsible
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for implementing the requirements of SSP 12.15, Revision 2
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and 0-PI-FPU-000.001.W, Revision 1 indicated that the
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procedures are not being adequately followed.
First, inadequate weekly inspections required by the two procedures resulted in the expired TFL permits not being identified / corrected by the licensee. Secondly, inadequate daily walkdowns as required by SSP 12.15, Revision 2, Appendix E, resulted in fire loads' being added to the permits after the permits had expired. The failure to adequately implement the requirements of SSP 12.15, FIRE PROTECTION PLAN, Revision 2, and 0-PI-FPU-000.001.W, OPERATIONS FIRE PROTECTION UNIT WEEKLY INSPECTION, Revision 1 is identified as a Violation (NCV 327,328/93-50-02),
Failure to follow the procedural requirements of SSP-12.15 and 0-PI-FPU-000.001.W. This NRC identified violation is not being cited because criteria specified in Section VII.B of the Enforcement Policy were' satisfied.
The inspector discussed his concerns related to the above violation with licensee management who initiated an Incident Investigation to evaluate the problems with the TFL permits program. Near the end of the inspection period, the inspectors were provided a copy of the completed II. The inspectors reviewed the II and concluded that appropriate corrective actions were implemented.
(2)
On October 27, the inspectors monitored licensee corrective actions for an operations configuration control issue involving the identification of an inoperable ERCW pump.
Earlier on October 27, the LB ERCW pump failed to start due to an inoperable pump breaker. A toggle switch which allows the breaker charging spring to reset was found in the wrong position. The licensee determined that the breaker had last been manipulated on October 25. The inoperable pump did not affect TS compliance of the ERCW system.
Immediate corrective actions for the event included a verification of all 6.9 KV breakers for operability. No other problems were identified. The licensee attributed the event to personnel error. Additional interim corrective actions included an operations standing order to verify breaker operability for all manipulated 6.9 KV and 480 V breakers.
Long term actions include a review to determine an improved method of.
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configuration control for the toggle switches and more generic end device operability. The inspector found the licensee's immediate corrective actions acceptable.
However, the inspectors also considered the event as a configuration control problem associated with operator inattention to detail.
In addition, adequate barriers were not in place to preclude this event.
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Biweekly Inspections The inspectors conducted biweekly inspections in the following areas: verification review and walkdown of safety-related tagouts in effect; review of the sampling program (e.g., primary and secondary coolant samples, boric acid tank samples, plant liquid and gaseous samples); observation of control room shift turnover; review of implementation and use of the plant corrective action program; verification of selected portions of containment isolation lineups; and verification that notices to workers are posted as required by 10 CFR 19.
(1)
On October 28, 1993, a test to demonstrate operability of the Unit 2 PASS was observed by the. inspector. Observation of this test was conducted as followup inspection to the licensee's commitment to have the PASS operable prior to restarting the reactors (reference NRC Inspection Reports 50-327/93-46 and 50-328/93-46).
The inspector noted that the sample containers and related equipment were readily available and that the sampling system for collection of reactor coolant and containment atmosphere samples was well prepared for the test. The test started at approximately 10:00 a.m., at which time the isolation valves to the PASS were opened. Diluted and undiluted samples of reactor coolant and containment atmosphere were collected. A sample of dissolved gases stripped from reactor coolant was also i
collected. By approximately 11:00 a.m. the samples had been collected, the in-line measurements were completed, and the
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isolation valves were closed.
The analyses performed in the laboratory were completed by approximately 12:40 p.m.
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analytical result for the boron concentration (corrected for
dilution) in the diluted reactor coolant sample was approximately 10 percent higher than the result from the undiluted sample. A previous study to establish the dilution factor indicated that the sampling error associated
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with diluted samples was approximately 24 percent.
In order to assure that no safety margin would be challenged by-reporting an overstated boron concentration, the licensee changed their procedures to account for that measurement uncertainty.
i Conditions 2.C.(23)F of License No. DPR-77 for Unit I and
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2.C.(16)g of License No. DPR-79 for Unit 2 authorized the licensee to operate the PASS as described-in their letters dated November 23 and December 21, 1983; January 9 and 10, i
1984; and March 23, 1984. Those letters described the licensee's commitments regarding PASS equipment and j
capabilities. The licensee indicated that a letter updating and clarifying those commitments would be submitted to the NRC but no firm date for submittal was established. The stated purpose of those changes was to delete references to specific brands of measurement equipment and to make the
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acceptance criteria for sampling and analytical results more consistent with those criteria delineated in NUREG-0737, Item II.B.3.
This issue, submittal' of a letter to update and clarify the licensee's commitments for PASS equipment
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and capabilities, will be tracked as au IFI (50-327/93-50-t 04,50-328/93-50-04).
Based on the above, the inspectors concluded that the licensee had demonstrated the ability to obtain samples of reactor coolant and containment atmosphere through the PASS
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and to complete analyses of those samples within 3 hoars.
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(2)
Hold Order On RCS Sample Valve 2-43-24 On October 25, 1993, Clearance Hold Order No. 2-93-1334 was issued to the A50S and maintenance personnel to rebuild or replace the Unit 2 RCS Hot Leg Sample Line valve 2-43-24 which had failed its leakage PMT. Work was performed on the valve under WR #C173549. The clearance was released on October 27 and the valve again failed its PMT. On October 28 clearance 2-93-1344 was reissued to the ASOS and maintenance to again work on valve 43-24 under the same WR.
The clearance was released by maintenance later in the day on October 28.
The system was returned to service _at approximately 1:31 a.m. on October 29 when the hold tags were removed; however, at the time of system restoration the clearance sheet still did not indicate a release by the ASOS.
During the Unit 2 morning status meeting on October 31, management was informed that the 43-24 valve had a through wall leak. Plant management directed that operations department isolate the valve from its pressure source due to potential personnel safety reasons. The Operations Superintendent informed the SOS to tag valve 43-24 so that it could not be operated. The clearance was not issued as requested by the Operations Superintendent and at 12:50 a.m.
on November 1 Chemistry opened valve 43-24 to take a RCS sample per procedure SI-50.
It should be noted that no hold clearance was violated when the chemistry sample was taken, because no clearance physically existed, even though the clearance sheet for 2-93-1334 still indicated that the ASOS had not released the clearance issued to him on October 28.
L At 10:25 a.m. on November 1, after the licensee identified that 43-24 was not isolated by a clearance, an administrative clearance, No. 2-93-1357, was. issued which closed two valves upstream of 43-24 for personnel safety considerations. At approximately 12:00 p.m. on November 1, clearance 2-93-1334 was reissued and at 6:04 p.m. on November 1 clearance 2-93-1357 was released.
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On November 4 the inspector reviewed the clearance sheet for 2-93-1334 in the Unit 2 control room and discovered that the-clearance sheet did not indicate a release for the clearance by the ASOS on October 28 nor did it indicate that the clearance had been reissued on November 1.
Although the documentation for the actual installation and removal of the hold tags was complete, the administrative portion, page 1, of the clearance indicating release time /date, was not completed when the release and reissue occurred.
Later in the day on November 4, in order to correct / update the clearance, the ASOS entered approximate times / dates, based on his recollection of the sequence of events, on clearance 2-93-1334 for those time /date blanks which had been previously omitted.
Site Standard Procedure SSP-12.3, EQUIPMENT CLEARANCE PROCEDURE, Revision 4, step 3.2.9 requires that clearance sheets shall be carefully and completely filled out for a clearance to ensure that all information is recorded and available for future reference. This requirement was not met in that neither the release by the ASOS on October 28 nor the reissuance of the clearance to the AS0S on November 1 was documented on the clearance sheet.
From approximately 1:31 a.m. on October 29 until 10:25 a.m. on November 1 no actual clearance existed on 43-24 even though the clearance sheet indicated that the ASOS had not released the clearance.
Failure to follow the requirements of SSP-12.3 is identified as a violation (328/93-50-03).
The inspector and the licensee had difficulty recreating the sequence of events regarding clearance 2-93-1334 primarily due to a lack of times / dates throughout the clearance form.
SSP-12.3, Appendix E, Page 3 of 4 of the clearance sheet,
Removal from Service and Release of Clearance, as designed, does not provide space to record times / dates of valve / breaker manipulations. The information would be useful in verifying when such manipulations occur and recreating a sequence of events if needed. Additionally, SSP-12.3 does not adequately define " Releasing a Clearance."
For purposes of configuration control it would be appropriate to clearly define the term. Discussions with operations personnel indicated that the term could mean either the administrative release by someone such as the i
AS0S or it could mean a " return to service" such as when a system is returned to its normal alignment upon hold tag
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removal. During review of Clearance Hold Order 2-92-1334,
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the inspector could not formally determine when clearances
are officially released. The inspector determined that-another work activity could have been assigned to the subject clearance after the tags had been cleared based on the clearence sheet front page.
Review of SSP-12.3.by the inspector determined that the procedure did not provide'
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adequate guidance for clearance control of.this evolution.
Failure to provide adequate guidance for establishment of clearance control is identified as an additional axample of violation (328/93-50-03).
The licensee instituted an incident investigation into this problem near the end of the inspection period.
Licensee management were very concerned about this process breakdown and corrective actions were being reviewed.
d.
Other Inspection Activities Inspection areas included the turbine building, diesel generator building, ERCW pumphouse, protected area yard, contrcl room, Unit 2 containment, vital 6.9 KV shutdown board rooms, 480 V breaker and battery rooms, and auxiliary building areas including all'
accessible safety-related pump and heat exchanger rooms.
RCS leak rates were reviewed to ensure that detected or suspected leakage from the system was recorded, investigated, and evaluated; and that appropriate actions were taken, if required.
RWPs were reviewed, and specific work activities were monitored to assure
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they were being accomplished per the RWPs. Selected radiation protection instruments were periodically checked, and equipment operability and calibration frequencies were verified.
e.
Physical Security Program Inspections In the course of the monthly activities, the inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities to include: protected and vital area access controls; searching of personnel and packages; escorting of visitors; badge issuance and retrieval; and patrols and compensatory posts.
In addition, the inspectors observed protected area lighting, and protected and vital areas barrier integrity.
f.
Licensee NRC Notifications (1)
On October 18, 1993, the licensee made a four hour notification to the NRC as required by 10 CFR 50.72 i
regarding a manual reactor trip during testing of the group demand position indicators on Unit 2.
The test was being conducted in MODE 3.
Operators were testing shutdown bank D
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group demand indicators in accordance with procedure. When operators attempted to step S/0 Bank D rods one step, the group 1 demand indicator went from 0 steps to 101 steps.
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Operators immediately stopped the test and manually tripped open the reactor trip breakers.
IRPI for S/D bank D, Group
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I rods did not indicate any movement of the rods. The q
licensee suspected a failure of the group demand position j
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indicator and initiated a work request to troubleshoot the problem. The indicator was latei replaced.
(2)
On October 24, 1993, the licensee made a four hour notification to the NRC as required by 10 CFR 50.72 regarding an earlier notification to the National Response Center. The notification to the response center was due to a hypochlorite spill which occurred on October 24, 1993 involving approximately 700 gallons of 10 to 13 percent solution. The inadvertent spill occurred when header ID developed a leak. According to the licensee, the hypochlorite solution did not reach the Tennessee River.
(3)
On October 24, 1993, the licensee made a four hour
>
notification to the NRC as required by 10 CFR 50.72 regarding a manual reactor trip. During withdrawal of the bank D shutdown rods, the group demand position indicator stayed at 180 steps while operators heard three audible steps occur. This condition exceeded the TS limit for demand position indication and operators took the appropriate actions to manually open the reactor trip breakers. The failed indicator had been recently replaced due to a related failure on October 18 as discussed in paragraph 3.f.1.
The licensee again replaced the failed indicator with a new device.
(4)
On October 25, 1993, the licensee made a four hour notification to the NRC as required by 10 CFR 50.72 regarding a manual reactor trip. While performing a post maintenance test on the D shutdown control rod group demand position indicator, operators manually opened the reactor trip breakers due to a failure of the new indicator. The failed indicator had been recently replaced due to related failures on October 18 and October 24 as discussed in-
>
paragraphs 3.f.1 and 3.f.3.
The licensee later determined that generic problems existed with the group of _ indicators that the licensee had in their parts inventory. The failed indicator was replaced with a proven device from the Unit I contro1' board.
g.
NRC restart inspection activities During this inspection period, NRC inspectors have maintained 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> monitoring of Unit 2 restart activities. This 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> monitoring coverage began during the last inspection period.
Those activities were discussed in inspection report 327, 328/93-
42.
,
Overall, the inspectors concluded that there were a number of areas in which improvement was apparent. Examples of these overall improved areas included communications during testing activities, identification of equipment problems, and a willing j
i i
..
13 attitude not to " live" with degraded equipment. The licensee's operations department continued to enhance and improve operator performance on a day to day basis.
However, several areas were also observed which needed additional management a+.tention regarding attention to detail. These were:
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Examples of poor shift turnover practices and lack of :
questioning attitude were observed whi:h i nladed:
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Omission of signoffs on page 50 cf 0-G0-2-3, PLANT STARTUP FROM LESS THAN 5% REA'JTOR POWER TO 30% REACTOR POWER, Revision 2 by a Unit 2 operations crew. A shift turnover had occurred between the time of the page omission and the inspector's identification.
None of the oncoming dayshift crew noted the problem.
This procedure was the prbary controlling procedure in effect for the plant s;artup.
Several shift turnover meetings and individual shift
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turnovers were observed.
Some of these turnovers did not include sufficient plant history for a crew returning after several days off. An example of this is the unawareness of the Unit 2 crew on October 22, 1993, that a 250 VDC Battery Board Abnormal alarm was received just prior to the 2A MFP speed malfunction on October 20, 1993.
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On October 23, hold clearance number 2-93-1317 was
-
issued to support the repairs on 2-FCV-62-70 in the letdown line.
Entry for the main control board (MCB)
switch for 2-FCV-62-69 was incorrectly entered as 68-69 and a work order number was not entered in the clearance responsibility section. The inspector
,
notified the Unit 2 ASOS who corrected both problems.
Other general areas needing attention included:
-
Additional improvement was needed regarding operator logs.
Specifically, the incompleteness of some log entries was noted. Operators frequently open issues and no closecut of the issue appears later in the logs, even if the issue was
,
adequately resolved on that shift.
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Some individual verbal turnovers are informal.
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An operator was observed holding a cup of coffee over the control room turbine control panel. This was coincident with there being approximately 12 personnel in the horseshoe area.
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,
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The inspectors concluded that operators were performing their duties in a safe manner. Operator performance during the letdown transient in this inspection period was noted to be good and well controlled.
However, further management attention and oversight to overcome the above deficiencies in operator performance is warranted.
Also, during the inspection period, operations crews changed from
,
a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift rotation. This change occurred on November 1, 1993. Licensee management also implemented a new shift turnover process coincident with the shift hour change. 'The process eliminated an oncoming crew meeting in a conference room prior to shift turnover.
Instead, the offgoing SOS would brief the o:scoming SR0s at his work station at the beginning of a new shift. Other operators would be obtaining individual briefs at their respective watch standing stations.
Each unit's operations crew would be briefed by the respective AS0S in the control room at each unit location.
The inspectors monitored several shift turnovers using the new turnover process, and noted some initial confusion and a general resistance to the change by some operations personnel. The inspectors will continue to monitor this process in the future.
Within the areas inspected, one violation and two non-cited violations were identified.
4.
Maintenance Inspections (62703 & 42700)
During the reporting period, the inspectors reviewed maintenance activities to assure compliance with the appropriate procedures and requirements.
Inspection areas included the following:
a.
During the inspection period, the inspectors reviewed root cause determinations and corrective actions for failures of two air operated valves to open during-an event which occurred on October 22 on Unit 2.
Both of the valves failed in their as-designed fail-closed position; however, their concurrent failure produced a unique situation where all RCS letdown was isolated for an extended period. The following reviews and conclusions were based
'
on the inspectors' observations and information available at the end of the inspection period. The subject event was previously discussed in detail in paragraph 3.a.2.
Failure of 2-FCV-62-70. Normal Letdown Valve The first valve to fail during the subject event was the normal RCS letdown valve 2-FCV-62-70 (Masonelian). This valve is air operated to open and spring to close.
The valve normally remains open during the entire fuel cycle and is only taken out of sarvice for CVCS outages. The valve failed via a 10 inch rupture in the air diaphragm. Once disassembled, the licensee discovered that
two pressure plates of different diameter, which were installed on the top and bottom of the air diaphragm, were reversed. The larger of the two plates should have been. installed on the top of the diaphragm. The incorrect reassembly of the valve pressure plates resulted in the diaphragm being over. stressed due to a lack of support and the subsequent failure.
The inspectors reviewed the previous maintenance history of the valve, including its Unit I counterpart. The Unit 2 valve and diaphragm had been worked twice during the current outage (May 1993 and July 1993). Both times the air diaphragm was replaced.
Review of maintenance records could not determine when the current
.
pressure plate assembly error was made. However, the licensee
concluded that it likely occurred during the May activity. Prior to the current outage, the Unit 2 diaphragm was replaced in January 1989 due to an actuator stem leak.
In addition, the Unit I letdown valve diaphragm was replaced in October of 1988 due to another valve assembly error. However, a review of work records could not definitively determine that the assembly problem was similar to the current error.
The licensee's incident investigation concluded that the root
cause of the incorrect air actuator assembly was due to personnel error.
Based on interviews with maintenance personnel, including i
those involved in the error, it did not appear that the assembly
problem was directly related to inadequate procedures or a lack of
'
training. Aside from this conclusion, Maintenance Management informed the inspectors that an air operated valve maintenance section would be developed with an appropriate level of detailed training guidance. A major contributor which was identified by the licensee was the physical location of the letdown valve.
It is located in the # 2 accumulator room and in a configuration which could adversely affect proper maintenance of the air actuator.
The licensee reviewed failure of the 2-FCV-62-70 air diaphragm for extent of condition. Due to the nature of the assembly error, the
licensee concluded that a failure mechanism of this type would exhibit itself in a short period of operation. Based on this, the review was limited to those valves worked during the Unit 2 forced
'
outage.
Further reductions in the number of valves to be inspected were made based on evaluations made by the licensee.
These reduction criteria included considerations such as which valves were operationally / safety significant, those valves in which diaphragm work was performed, and valve specific internal component configurations. Two valves were selected for inspection (2-FCV-63-87 and 2-LCV-6-147A). The diaphragms on botn of the valves were found correctly assembled. However, an additional problem was identified on 2-LCV-6-147A, in that, a valve diaphragm pressure plate was insUled with the rounded edge away from the diaphragm. The roundec edge should have been installed toward the diaphragm for protection from cutting. This valve had also been
.
worked during the Unit 2 forced outage. The diaphragm for 2-LCV-6-147A was examined and no noticeable degradation was identified.
The licensee later inspected 2-LCV-6-166A based on the later problem and did not identify any further discrepancies.
The licensee plans on performing selected inspections on Unit I similar valves prior to restart of Unit 1.
The inspector concluded that the licensee's review of the 2-FCV-62-70 failure was adequate for initial Unit 2 restart and that the methodology used to determine where other similar assembly errors could have been made was acceptable. The inspectors also concluded that the two identified valve assembly errors were examples of poor maintenance craft performance and indicative of a lack of supervision during the work activity. The inspectors will review the results of the Unit I valve assembly verifications during future inspections. The incorrect assembly of the identified air operated valves is identified as a maintenance weakness.
Failure of 2-FCV-62-54. Excess Letdown Valve The second air operated valve failure during the subject event occurred on 2-FCV-62-54, excess letdown valve. This valve, which is typically closed, was also air operated to open and spring to close. During the event, the licensee determined that the valve failed to open due to a failure of its air supply regulator.
The valve was subsequently opened during the event via the placement i
of an air jumper around the failed regulator. Subsequent repairs to the valve included diaphragm replacement due to the emergency air supply exceeding the recommended air supply to the valve.
The licensee later examined the failed air regulator and determined that the internals were badly worn, including the diaphragm disc and seat. The seat holes had become scored in'an oval shape and the pilot disc had deep circumferential grooves.
Due to this degradation, the diaphragm seat depth had increased to a point where full stroke of the main pilot was not possible.
When tested, the regulator would only develop 25 psig versus approximately 40 psig normal design.
Further investigation revealed that an airleak, downstream of the regulator, had caused the regulator to constantly be adjusting for the variations in pressure.
It was determined that this repetitive cyclic' action resulted in the degradation to the regulator internals and subsequent failure to maintain adequate supply pressure for 2-FCV-62-54.
To evaluate the extent of condition which could adversely affect Unit 2 operation, the licensee developed the following criteria for air regulator inspection:
1)
No excessive air coming from the air leakoff port in the regulator cove y
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t
2)
Local observation of the pressure gage on the regulator showing no sign of rapid cyclic motion.
3)
No air leaks found downstream of the pressure regulator or solenoid.
4)
The regulator has not had excessive adjustments made to compensate for wear.
Field inspections utilizing the above criteria were performed on 55 regulators considered by operators as safety significant air operated valves. The basis for limiting the scope of inspection to the 55 included valve safety significance, fail safe positions, incorporation of valves in the Section XI testing program, and a lack of previous generic problems with air regulators.
Based on the inspections, 9 additional regulators were disassembled for further evaluation. None of the additional regulators had significant wear (such as identified on the 2-FCV-62-54 regulator) which could prevent proper operation. Only slight wear was found on the additional regulators. -Based on the results of the inspections, the licensee concluded that the failure of the 2-FCV-62-54 regulator was limited and occurred due to the repetitive cycling caused by a downstream air leak.
Eight of the regulators inspected were replaced as a precautionary measure.
The inspectors reviewed the licensee's immediate corrective actions for the regulator problem and considered them to be _
adequate. This was based on review of the_ inspection criteria, review of the chosen list of valves, inspection of the disassembled regulators, and independent field inspections of additional air regulators on Unit 2.
The inspectors did identify _
an air leak on the body of a regulator for the # 2 MFW bypass valve. This problem was corrected by the licensee and determined not to be associated with the subject failure mechanism.
The inspectors concluded that the root cause of the regulator failure on 2-FCV-62-54 was directly related to the material condition of the air system (ie. the existence of a downstream leak which initiated the failure).
In addition, the inspectors noted that air regulators are not encompassed in a preventive maintenance program. The inspectors also noted that 2-FCV-62-54 was not being periodically stroked prior to the event. Although the inspectors did not identify any requirements to periodically stroke the valve, the inspectors concluded that this action _would have'likely identified the failure prior to it being self disclosing during the event. Based on the event, the licensee is considering implementation of a PM program which would provide for routine regulator inspections based on the criteria derived from the event. The licensee is also reviewing the event failures as they apply to their reliability centered maintenance program. The
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inspectors considered the licensee's immediate corrective actions for the air regulator problems to be adequate. The inspectors will further review air regulator and air system material conditions and review the results of Unit I walkdowns during future inspections.
b.
During the inspection period, the inspectors reviewed recent events related to the maintenance of the plant fuel oil supply system and the measures taken by the licensee to ensure that the EDGs fuel source was acceptable. On October 26, a problem was identified between Operations and Chemistry personnel which resulted in both of the plant diesel fuel oil tanks not being
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available for makeup to the EDG TS required fuel tanks. During normal receipt of diesel fuel, site chemistry samples the incoming shipment to ensure that its flashpoint is correct. Once this is completed, the shipment is allowed to be transferred to the #1 fuel oil tank. This tank feeds the auxiliary boiler and can also be transferred to the #2 fuel oil tank. The #2 fuel oil tank is i
the normal flow path for refilling the TS required seven day tanks and the TS EDG skid mounted day tanks. When the #2 fuel oil tank becomes low, the #1 tank is sampled for the appropriate quality related parameters. This testing requires 16-20 hours for completion. Upon satisfactory quality related test results, the
- 1 tank is transferred to the #2 tank.
On October 26, the AUD performing the receipt of the new fuel was informed by chemistry that the initial sample was satisfactory.
However, the AU0 interpreted that the quality related verification had been performed, rather than just a flash point verification.
Upon reviewing the amount of fuel in the #1 and #2-tanks, the AVO decided to fill the #2 tank with the new shipment. This was allowed by the procedure.
It was subsequently identified that both of the tanks now contained fuel that had not been quality verified. Quality related sampling was performed and revealed that the #2. tank had a' sediment content which was at the allowable limit. The inspector reviewed fuel oil system drawings and questioned whether the sediment identified in the #2 tank had been introduced by flowing through normally stagnant lines when the AVO inappropriately filled the tank. The licensee informed the inspectors that no new fill lines were used and that an action plan was developed to filter the contents of tank #2 to preclude any sediment transfer to the safety-related EDG tanks.
In addition, proposed corrective actions for the problem include procedure revisions to top off the seven day tanks prior to the addition of new fuel to the non-safety fuel storage tanks and to only allow the receipt of new fuel to go to the #1 tank. The inspectors concluded that the licensee's corrective actions were appropriate. However, the inspectors also concluded that this event was an example of a continuing communications problem between Operations and Chemistry personnel.
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e
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c.
The inspector observed Unit 2 Individual Rod Position Indicator maintenance on 10/21/93 for Shutdown Bank A, rod H6, which had drifted out of tolerance. The Instrument Technician inadvertently
disconnected the signal input for rod M2 causing an alarm and a
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rod bottom light to be received in the control room. The unit operators responded appropriately and verified the rod had not
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actually dropped. The technician informed the control room of his
.
error promptly and suspended his maintenance. The inspector reviewed the procedure, 0-PI-IXX-085-001.0, which was performed by the technician and concluded that the format of Table 1, which contains the signal disconnect wire numbers for all control rods, contributed to the mistake by the technician. However, the primary cause sas inattention to detail by the technician.
The inspector observed the same technician performing the identical evolution the following day on a different rod. Table 1 in the procedure had been revised since the previous day's problem to eliminate the chance for confusion that had contributed to the technician's error.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections (61726 & 42700)
During the reporting period, the inspectors reviewed various surveillance activities to assure compliance with the appropriate procedures and requirements. The inspection included a review of the following procedures and observation of surveillance:
a.
At the beginning of the inspection perloo, the inspectors reviewed the completed surveillance instructions for testing of both trains of the control room emergency ventilation system. The procedures reviewed adequately documented that the CREVS provided pressurization of the control room as required by TS.
b.
The inspector observed Unit 2 control room coordination of local condensate booster pump post-maintenance testing on October 20,-
1993. A red running light was received on the B pump in the control room that was not expected by the operators. The operator verified the pump was not running by verifying pump motor amps.
However, he could not explain the cause of the red light. The
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local operator had placed the breaker for the pump in test which illuminates the red pump running light on the main control board although the pump is not actually running. _ The control room i
operate was unaware of this even though he was closely monitoring the evolution. The Unit 2 ASOS immediately suspended the maintenince and directed all parties involved to reverify their expectec actions before proceeding. This was an example of a breakdom in communications during testing.
c.
On October 21, the inspectors observed the performance of 0-PI-47-760, MAIN TURBINE TRIP TESTS, Revision 5.
The performance
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included actual overspeed (electrical and mechanical) trip tests.
Overall coordination of the test activities was good. During the performance of the electrical overspeed trip, the turbine failed to trip at 1985 rpm. The inspectors noted that the operators were cautious not to exceed the allowable acceptance' criteria band of 1975 to 1985 rpm per the procedure. The licensee stopped the test and discussed available options with the turbine vendor.
It was later determined that the ultimate limit was 1998 rpm. A re-test was performed and the turbine tripped at 1983 rpm, within the acceptable range of the procedure.
Within the areas inspected, no violations were identified.
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6.
Evaluation of Licensee Self-Assessment Capability (40500)
During this inspection period, selected reviews were conducted of the licensee's ongoing self-assessment programs in order to evaluate the effectiveness of these programs, a.
During this period, the inspectors reviewed several activities which had been conducted by the Sequoyah ISEG.
Early in the period, the inspectors noted a presentation to the MRC, where the ISEG had identified a deficiency in the review process of the MRC.
The ISEG presented a causal factors chart as part of the review process which clearly depicted a point where the MRC could have been a barrier in prevention of a second spraydown of a USST. The MRC received the report in a constructive manner. The inspectors concluded that this type of event review was constructive and provided plant management with critical assessment of performance
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for improvement.
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The inspectors also reviewed several ISEG reports which had been prepared over the last three months. The inspectors concluded that the reports were thorough and provided management with facts with which meaningful corrective actions could be implemented.
Some examples of the report findings included (1) test delays i
because of errors in a design package, (2) lack of technical bases for an abnormal operating instruction, and (3) inconsistencies in
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the Sequoyah surveillance test program when compared with other industry practices.
i The inspectors concluded that the Sequoyah ISEG was providing plant management with good assessment findings in a manner which
,
clearly identified weaknesses in programs or processes. The ISEG i
reviews also satisfied the requirements of TS 6.2.3 which requires that the ISE shall function to examine plant operating characteristics, NRC issuances, industry advisories, LERs and other sources which may indicate areas for improving plant suety.
l b.
During the period, several PORC meetings were monitored by the inspectors.
The insepctors determined that proper attendance was
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accomplished by the PORC chairman and that all issues presented to PORC were addressed in an adequate manner.
Within the areas inspected, no violations were identified.
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7.
Licensee Event Report Review (92700)
The inspectors reviewed the LERs listed below to ascertain whether NRC reporting requirements were being met and to evaluate initial adequacy of the corrective actions. The inspector's review also included followup on implementation of corrective action and/or review of licensee documentation that all required corrective action (s) were either complete or identified in the licensee's program for tracking of outstanding actions.
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a.
(Closed) LER 327/93-16, A Phase A Isolation, Auxiliary Building Isolation, and Containment Isolation Were Manually Initiated as a Result of Fuel Assembly Failing to Remain in an Upright Position After Being Released. The issue involved manual initiation of the subject ESF systems in response to abnormal operating procedure as a result of a tilted fuel assembly during Unit 1 fuel reload. All equipment operated as espected. The inspectors reviewed the event and consider that licensee actions were appropriate.
b.
(Closed) LER 327/93-17, Failure to Comply with Technical Specification Limiting Candition for Operation Action Statement and Notify NRC by Telephone Regarding the Auxiliary Building Fire Suppression System Being Nenfunctional.
The issue involved operators not making a call to the NRC as required by TS LC0 3.7.11.1, ACTION b.2.a.
Tte other LCO ACTION statements were met; however, the operators failed to note entry into the LC0 ACTION
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and make the call due to personnel error. The inspectors reviewed
the event and noted thrA only the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> telephone call required by the TS was not accomplished during the maintenance activity.
All other actions were complied with.
Several other corrective actions were implemented to prevent recurrence. One of the corrective actions included a change request to eliminate the call requirement from TS. This event was addressed in inspection report 327, 328/93-23. An NCV was issued in that report for this
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event.
c.
(Closed) LER 327/93-18, Diesel Generator (D/G) Start as the Result l
of Improper Work Order Planning. The issue involved inadequate planning input for work by a system engineer. 'In addition, the
!
independent reviewer for the procedure failed to identify that the
system engineer had made a mistake. During performance of the work, an ESF signal was generated. Corrective actions included
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securing of the EDGs and conducting an investigation of the event.
It was concluded that the engineer and the independent reviewer i
did not specify appropriate configuration for replacement of a blackout relay. The inspectors reviewed the LER and discussed the event with the system engineer. The licensee determined that part l
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t:
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i of the cause of the event was use of complicated wiring circuits
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which made tracing of the circuitry difficult. Additional I
corrective actions included instructing electrical planners and
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engineers to use highlighters-for tracing of' complicated wiring J
circuits.
Personnel were held responsible for. their actions.
d.
(Closed) LER 327/93-19, Containment Isolation Resulting From a Loss of Control Air. The. issue involved both the nonessential a
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control air headers being. isolated during implementation of a clearance tagging. Operators responded to'the loss of control air
>
event and determined that the tagging clearance was in error.
They restored control air by backing out'of the clearance. _The
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cause of the event was determined to be a drawing error..This'
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event was discussed in inspection report 327,328/93-33.
In that
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report a violation was issued for this event. The inspectors will
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review licensee additional corrective actions during closeout of l
the violation.
e.
(Closed) LER.327/93-20, Auxiliary Building Gas Treatment Start as.
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a Result of a Fire in the Unit 2 General Supply Fan Room. The i
issue involved securing of all auxiliary' building general supply
.l fans due to the subject fire.
Immediate corrective actions
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included extinguishing of the fire. - In addition, the ABGTS, train
B was manually initiated to provide ventilation to affected areas.
.
The inspectors reviewed the LER and determined that licensee _
l actions were appropriate for the event.
l f.
(Closed) LER 327/93-22:
Inability of the ABGTS to Perform its
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Intended Safety function in the Event of an Accident.
The issue i
involved the potential for the ABGTS design function to be negated -
if the auxiliary building general ventilation and exhaust fans and the _ fuel-handling exhaust fans failed to automatically stop.
It i
was identified that' the control circuity for these fans is non-IE,.
therefore, it was not assured.they would fall. in the off position.
As corrective action, the licensee issued _EA-0-1, EQUIPMENT CHECKS
FOLLOWING ESF ACTUATION, Revision 0, to provide instructions for-q ensuring proper operation of~ equipment outside the MCR horseshoe
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following safety injection. -This procedure' included steps to ensure that in the' event of an accident, the auxiliary building general ventilation supply and exhaust fans and the fuel-handling
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exhaust fans are stopped. Procedure E-0,' REACTOR TRIP'OR SAFETY INJECTION, Revision 13, was issued to require reference to EA-0-1-i following an ESF actuation. The inspectors reviewed the E0Ps and-
verified that appropriate changes were'made to stop'the referenced i
fans.
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Within the areas inspected, no violations were identified.
'j 8.
Action on Previous Inspection Findings (9270),92702)
]
l (Closed) IFI 327,328/92-27-01, Apparent Violation for' Falsification of Plant Records; IFI 327,328/92-30-03, Review of Incorrect ERCW Breaker
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i Testing; and IFI 327, 328/92-35-01, Apparent violation of 10CFR50.9 for Falsification of Firewatch Records. The issues involved licensee identification of discrepancies in AU0 rounds, procedural discrepancies for ERCW breaker testing, and apparent discrepancies in firewatch rounds. NRC reviewed the licensee's evaluation in this area and addressed this issue in a letter to TVA dated October 15, 1993. The letter included a Notice of Violation for the issues and discussed licensee actions taken to close these issues.
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Within the areas inspected, no violations were identified.
9.
Leak Sealant Practices The inspector reviewed the licensee's program for use of temporary leak
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sealants. The sealant is commonly referred to as Furmanite.
a)
Use The licensee has contracts with Furmanite, Inc. for services and materials used in leak sealing processes. The processes used at i
Sequoyah are the same available throughout the industry. Some processes used are injection clamps for flange leaks, enclosure boxes for leaks in elbows, wire wrap of joints, packing gland injection and " killing" of a thru-leak in a valve.
b)
Scope Sealants have been used primarily on nonsafety-related equipment; however, some safety-related applications have been made in the
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past.
Sequoyah had experienced significant secondary side erosion / corrosion problems and leak sealant was used excessively prior to the dual unit forced outage in March of 1993. During the dual unit outage, the licensee recognized the excessive use and has implemented hardware repairs to essentially eliminate the current use of leak sealant. Currently, there are no uses on safety related equipment and approximately four applications on non-safety equipment. Both safety and non-safety applications must receive Engineering approval in accordance with procedures.
c)
Procedures Repairs are performed under work orders prepared by SSP 6.63, CONTROL OF TEMPORARY LEAK SEALANT REPAIRS.
For both safety-rel-ated and non safety-related equipment the approval is processed using the DCN process. Work orders are developed from vendor supplied procedures that cover the particular process to be used.
d)
Control The control of the type and amount of injected material is under the contractor procedures which are reviewed as part of the DCN.
This ensures that requirements for chemical composition and volume
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of sealant to be injected be followed. The licensee maintains a log of the total amount of leak sealant injected.
e)
Limitations The licensee's' policy on length of use is to make the temporary repair permanent at the next refueling outage or system outage.
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Any extensions must be approved for use by NE.
f)
Oversight The use of Furmanite is covered as part of a QA annual audit and as part of routine work coverage.
Per QA management, all jobs identified as involving Furmanite receive special attention due to their significance.
g)
Management
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Plant Management is made aware of temporary repair methods being proposed on operational equipment by either outage scheduling meetings, verbal communication, or by a Plant Safety Comittee Review of a Furmanite job procedure.
The inspectors concluded that the licensee's current use and reviews for Furmanite applications were acceptable. The inspectors will continue to monitor this area _in detail based on the licensee's previous history of extensive use.
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10.
Exit Interview The inspection scope and results were summarized on November 9,1993,
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with those individuals identified by an asterisk in paragraph I above.
j The inspectors described the areas inspected and discussed in detail the
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inspection findings listed below.
Proprietary information is not contained in this report. Dissenting comments were not received from the licensee.
Item Number Description and Reference VIO 328/93-50-01 Failure to operate Unit 2 in MODE 3 as required by SSP 12.1.
NCY 327, 328/93-50-02 Failure to follow the procedural
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requirements of SSP-12.15 and 0-PI-FPU-000.001.W.
VIO 328/93-50-03 Failure to follow the requirements
of SSP-12.3.
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IFI 327,328/93-50-04 Submittal of a letter to update and clarify the licensee's commitments j
for PASS equipment and capabilities.
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Strengths and weaknesses summarized in the results paragraph were discussed in detail.
Licensee management was informed of the items closed in paragraphs 7 r
and 8.
II.
List of Acronyms and Initialisms ABGTS -
Auxiliary Building Gas Treatment System
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Auxiliary Feedwater ASOS -
Assistant Shift Operations Supervisor AVO
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Assistant Unit Operator CCP
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Centrifugal Charging Pump
.i CCS
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Component Cooling Water System CFR
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Code of Federal Regulations CR Control Room
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CREVS -
Control Room Emergency Ventilation System CR0
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Control Room Operator CVCS -
Chemical and Volume Control System CVI
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Containment Ventilation Isolation DCN
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Design Change Notice DRP
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Division of Reactor Projects EDG
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Emergency Diesel Generator E0P
-
Emergency Operating Procedure ERCW -
Essential Raw Cooling Water ESF
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Engineered Safety Feature FCV
-
Flow Control Valve FSAR -
Final Safety Analysis Report GPM
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Callons Per Minute HX Heat Exchanger
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Individual Data Package IFI
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Inspector Followup Item IM
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Instrument Maintenance IR
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Inspection Report
IRPI -
Individual Rod Position Indicator
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Independent Safety Engineering
ISEG -
Independent Safety Engineering Group
KV
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Kilovolt
LC0
Limiting Condition for Operation
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Level Control Valve
LER
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Licensee Event Report
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MCB
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Main Control Board
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Main Control Room
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Main Feedwater Pump
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Management Review Committee
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Non-cited Violation
NRC
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Nuclear Regulatory Commission
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Nuclear Reactor Regulation
0ATC -
Operator At The Controls
Operational Control Center
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PASS -
Post Accident Sampling System
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Pressure Control Valve
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Plant Evaluation Review Panel-
PERP
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Plant Operations Review Committee-
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Post-maintenance Test
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Parts per Million
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Quality Assurance
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RCDT -
Reactor Coolant Drain Tank
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Reactor Coolant System-
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RII
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NRC Region ~II
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Radiation Monitor
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Revolutions Per Minute
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Radiation Work Permit
RWST --
Refueling Water Storage Tank
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Surveillance Instruction
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S0
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System Operations
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System Operating Instruction
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SOS
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Shift Operating Supervisor
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Senior Reactor Operator
SR0
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Site Standard Practice
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TAVE
Average Temperature of the Reactor Coolant System
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TFL
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Transient Fire Load
TS
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Technical Specifications
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Unresolved Item
Unit Station Service Transformer
USST
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Voltage Direct Current
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Violation
Work Order
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Work Request
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