IR 05000395/1993015
| ML20045E421 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 06/02/1993 |
| From: | Cantrell F, Haag R, Keller L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20045E398 | List: |
| References | |
| 50-395-93-15, NUDOCS 9307020099 | |
| Download: ML20045E421 (13) | |
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$ /* b0%g UMITED STATES
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g NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET, N.W.
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's ATLANTA, GEORGI A 30323 49.....,o Report No.:
50-395/93-15 Licensee:
South Carolina Electric & Gas Company Columbia, SC 29218 Docket No.:
50-395 License No.: NPF-12
Facility Name: Virgil C. Summer Nuclear Station Inspection Conducted: April 1 through May 10, 1993 Inspectors:
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c,d /9/9 R. C. Haag, Senior Resident Inspector Date Signed hIL1bk 6/2/93 L. A. Keller, Resident Inspector Date Signed J. L. Shackelford, Reactor Inspector (April 5-9, 1993)
L. Garner, Senior Resident Inspector, H. B. Robinson (May 1, 1993)
R. W. Wright, Project Engineer (May 3-7, 1993)
Approved by:
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f 6/2/93 FToyd S. Cantrell, CKief -
Date Signed Reactor Projects Section IB Division of Reactor Projects SUMMARY Scope:
This routine inspection was conducted by the resident. inspectors onsite in the areas of monthly surveillance observations, complex surveillance observations, monthly maintenar.ce observations, operational safety verification, engineered
safety feature system walkdown, action on previous inspection findings, and i
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onsite follow-up of events at operating power. reactors.
Selected tours were i
i conducted on backshift or weekends...These tours were-conducted on eight occasions.
l Results:
Overall coordination and implementation of the integrated safeguards tests was good. A procedural deficiency was identified for the loss of offsite power portions of the test in that the documentation of a Technical Specification requirement was not provided (paragraph 4). All maintenance activities 9307020099 930602 PDR ADOCK 05000395 G
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observed were well planned and executed (paragraph 5). As a result'of inspections in_the area of reduced inventory operations, the-licensee's
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response to Generic Letter 88-17 was found to be unacceptable (Paragraph 6.b).
A non-cited violation was identified for failure to comply with a procedural requirement during dilution to criticality (paragraph-6.c).
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J REPORT DETAILS 1.
Persons Contacted Licensee Employees
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F. Bacon, Manager, Chemistry W. Baehr, Manager, Health Physics K. Beale, Supervisor, Emergency Services
- C. Bowman, Manager, Maintenance Services
- M. Browne, Manager, Design Engineering
- B. Christiansen, Manager, Technical Services
- M. Fowlkes, Manager, Nuclear Licensing & Operating Experience S. Furstenberg, Associate Manager, Operations W. Higgins, Supervisor, Regulatory Compliance A. Koon, Nuclear Operations Project Coordinator
- D. Lavigne, Generel Manager, Nuclear Safety K. Nettles, General Manager, Station Support H. O'Quinn, Manager, Nuclear Protection Services
- H. Quinton, General Manager, Engineering Services J. Skolds, Vice President, Nuclear Operations
- G. Taylor, General Manager, Nuclear Plant Operations
- B. Waselus, Manager, Systems and Performance Engineering
- B. Williams, Manager, Operations
- R. White, Nuclear Coordinator, South Carolina Public Service Authority
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Other licensee employees contact,ed included engineers, technicians, operators, mechanics, security force members, and office personnel, i
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the-last paragraph.
2.
Plant Status The unit was in a planned refueling outage throughout most of the inspection period. On May 1,1993 the reactor was made critical. On
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May 3,1993 the main generator output breaker was closed, completing refueling outage seven. On May 6,1993 the plant achieved 61 percent power when a problem with a generator stator cooling valve forced a power reduction to 30 percent. As of the end of the inspection period, power was at 98 percent.
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Other inspections or meetings:
J. P. Stohr, Director, DRSS, was onsite April 1-2, 1993, to tour
the plant and meet with licensee management and the resident inspector.
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J. L. Shackelford, Reactor Inspector, Region II, was onsite
April 5-9, 1993, to provide site coverage.
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During the week of April 12, 1993, a regional inspection in the
area of In-Service Inspection (ISI) was performed (NRC Inspection Report No. 395/93-13).
During the week of April 26, 1993, a regional inspector was onsite
to prepare for an engineering and technical support inspection scheduled for the week of May 17, 1993.
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L. Garner, Senior Resident Inspector, Region II, was onsite May 1,
1993, to provide startup coverage.
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R. W. Wright, Project Engineer, Region II, was onsite May 3-7,
1993, to provide site coverage.
3.
Monthly Surveillance Observation,(61726)
The inspectors observed surveillance activities of safety-related systems and components listed below to ascertain that these activities were conducted in accordance with license requirements. The inspectors verified that required administrative approvals were obtained prior to initiating the test, testing was accomplished by qualified personnel in
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accordance with an approved test procedure, test instrumentation was calibrated, and limiting conditions for operation were met. Upon completion of the test, the inspectors verified that test results
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conformed with technical specifications and procedure requirements, any deficiencies identified during the testing were properly reviewed and resolved and the systems were properly returned to service.
Specifically, the inspectors witnessed / reviewed portions of the
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following test activities:
ECCS pump operability test (STP-230.006A). During the performance
of the ECCS pump operability testing for the "C" CCP, the test personnel noted that while raising the pump flowrate from approximately 695 gpm towards the desired flowrate-of 700 gpm, smoke emanated from the inboard pump bearing. The control room shift supervisor immediately stopped the test and secured the charging pump to prevent possible damage. Additionally, the valve lineup in effect at the time was secured, and the
"A" CCP was placed into service to pr0 vide makeup to the reactor cavity. _The control room staff acted in a positive manner to control the situation._ The operators were alert to the situation and responded quickly to stop the cavity level decrease. Subsequent investigations by the
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licensee determined that the cause of the problem was due to rubbing in an oil seal of-the pump. - It was determined-that-no bearing
damage had occurred to the pump.
ECCS Flow Balance (STP-230.006B). The inspector observed various
portions of the ECCS flow balance. The testing was well coordinated and the test personnel maintained close contact with control room operators during the performance of the procedure. No deficiencies were noted.
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Differential pressure (DP) testing of XVG08887A-SI (PTP 270.012).
- On April 23, 1993, the inspector observed full flow / design DP testing of the subject valve. Normal position indication and control for this valve is provided by a CMC switch on the main control board. Additional indication is provided by an ESF status light. During the open-to-close portion of the test, the closed indication was not received on either the CMC switch or the ESF status light.
The valve was subsequently declared inoperable while the M0 VATS data was analyzed. The data indicated that the valve's torque switch actuated prior to the valve fully closing. This was unexpected as the calculations indicated the valve should have fully closed under the test conditions. The licensee attributed this to i
rate-of-loading phenomena.
The inspector noted that even though the valve did not fully close, as indicated by the status lights, flow indicators showed zero flow past the valve and therefore the valve would have performed it's design basis function.
The licensee subsequently bypassed the torque switch so that the valve actuator shuts off from the limit switch. The licensee then ran a series of 5 tests which all indicated satisfactory valve performance.
Safety injection valve XVG08887A-SI did not completely close under full flow / design DP testing. All other observed tests were performed in accordance with procedural requirements and demonstrated acceptable results.
4.
Complex Surveillance (61701)
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This inspection was used to ascertain whether functional testing o^ the more complex safety-related systems and subsystems were in conformance with regulatory requirements. The surveillance activity chosen for this inspection was integrated safeguards testing (STP 125.010, 125.011, 125.017,125.018).
The inspector reviewed the procedures prior to testing, to determine if they were hdequate to demonstrate compliance with applicable TS surveillance requirements associated with safety injection and blackout conditions.
Portions of the tests were witnessed to verify that minimum crew requirements were met, test prerequisites were completed, special test equipment was calibrated, and that safeguards equipment operated within specifications. Additionally, the inspector verified portions of the licensee's test results and data.
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Overall coordination and iniplementation of the integrated safeguards tests were good. With only a few minor exceptions, equipment operated properly. The procedures had the necessary detail to adequately demonstrate compliance with TS, with one-minor exception. This exception
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involved the procedures for loss of offsite power (STP 125.017/18).
These procedures are designed in part to meet the requirements of TS surveillance requirement 4.8.1.1.2.g.14.
This TS requires verification that "within 5 minutes of operat'ing the diesel generator for at least one hour at a load of 4150-4250 KW the diesel starts on the auto start signal (loss of offsite power signal)".
The data sheet for these procedures did not document the time the diesel was secured from the one hour run, therefore there was no documentation, within the procedure, for the 5
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minute requirement. The inspector independently verified, via operating logs, that the diesels were started within 5 minutes of securing from the one hour run. The licensee indicated that the procedure data sheet would be revised to include the time the diesels were-secured from their one hour runs.
5.
Monthly Maintenance Observation (62703)
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Station maintenance activities for safety-related and B0P systems and components listed below were observed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards and in conformance with TS as applicable.
The following items were consid~ered during this review: approvals were obtained prior to initiating this work, activities were accomplished using approved procedures and were inspected as applicable, functional testing and/or calibrations were performed prior to returning components or systems to service, activities were accomplished by qualified personnel, proper materials were used, and radiological and fire prevention controls were implemented if applicable.
Penetration access area auxiliary building fire barrier inspections
(STTS 0049596). The South, West, and East wall fire barrier penetration seals (silicone foam, leaded elastomer, pressure seals, cement grout, and kaowool) in room PAA-63-01, elevation 463, were visually inspected for rejectionable cracks, holes, separations, and surface gouges per criteria specified in STP 728.035. Although all penetration seals examined in the room were found satisfactory, the subject STP requires visual inspection of each penetration seal from both sides.
Discussions with the civil maintenance inspectors disclosed that meeting this requirement is occasionally impossible.
A few penetrations are inaccessible due to permanent coverings and a few are only accessible during an outage. Discussions with management on this issue disclosed that these inaccessible l
penetrations will be noted on the fire barrier inspection data
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sheets, stating the reason for their inaccessibility; and efforts will be made to assure that outage related' penetration seals are scheduled to be inspected during the next outage.
Emergency lighting battery testing (PMTS P0163972, P0163981,
P0163976, P0163982)..The inspector observed the inservice testing of two intermediate and two turbine building emergency lighting components. After the inservice testing, the component's batteries were-removed from their, units..and bench-tested by subjecting them to a fixed load for at least eight hours.
All battery's passed the load duration testing per EMP 230.001, were recharged, reinstalled, and again inservice tested to insure their units functioned properly.
No discrepancies were noted.
Investigation and repair of steam flange leak in high pressure
turbine inlet line (MWR 93M3137). The lagging and insulation covering the flange were removed and the flange bolts retightened
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without success.
The nuts on the flange studs were removed and replaced with special nuts equipped with fittings through which a furmanite type material was pumped by contracted personnel. This fix appeared to have worked but will be verified by further licensee monitoring as the plant increases power to 100 percent.
Inspect, service, and clean various air conditioning condenser units
and air handling units (PMTS 165823, 165832, 165833, 165821, 165828, 165829). Routine preventive maintenance in accordance with applicable portions of procedures HMPs 460.003, 460.022, and 460.025 was observed performed satisfactorily on the condenser units and air handling units serving the HP count room, and TSC computer room located in the control building. No discrepancies were noted.
Installation of new potential transformer in circuitry associated
with the "B" EDG synchroscope (MWR 215840008). The circuitry associated with the "B" EDG synchroscope has had problems with voltage spikes.
MRF 21584 directed replacing a 1:1732 ratio potential transformer (PT) with a 1:1 ratio PT. The inspector noted that all aspects of this maintenance activity were satisfactory.
The maintenance activities discussed above were well planned and executed.
6.
Operational Safety Verification (71707)
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Plant Tour and Observations The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator adherence to approved procedures, TS, and limiting conditions for operations; and review of control room operator logs, operating orders, plant deviation reports, tagout logs, and tags on components to verify compliance with approved procedures.
b.
Reduced Inventory following Steam Generator Work On April 16, 1993, the unit went into a second reduced inventory in order to remove steam generator nozzle dams and perform work on various valves. The inspector observed the drain down from 4 inches below the reactor vessel flange to mid-loop plus 9 inches.
The inspector noted that RVLIS was inoperable during the drain down and that the ultrasonic level indicators were unable per design-to provide level indication until level-receded below the top of the flow area of the RCS hot legs at the junction with the Reactor Vessel.
This meant that the only level indication, while the RCS was between 4 inches below the flange and the top of the hot legs, was tygon tubing. The ultrasonic level indicators did perform well once level went below the top of the hot legs. The inspector considered the pre-job briefing for this activity to be thorough.
Control room demeanor and communications were good.
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SCE&G Company's response to the six programmed enhancements identified in Generic Letter 88-17 dated February 2,1989 states,
"V. C. Summer will have installed prior to the end of the next refueling outage (RFS) two independent RCS level indication systems.
Each will measure, indicate, and alarm the RCS level".
NRR concluded that acceptance of licensee GL 08-17 responses would be based on verification by NRC inspection of licensee commitment actions per TI 2515/103.
Both GL 88-17 and TI 2515/103 require two independent RCS level indication systems to be operable prior to entering a reduced inventory condition, which is defined as a condition where the reactor vessel level is lower than three feet (nominal) below the reactor vessel flange. However, as stated above, the plant had only one RCS level indicator (tygon tubing) capable of providing the full range of indication before entering their second reduced inventory condition.
Subsequent to this inspection the licensee was notified that Summer's response to GL 88-17 was unacceptable, and therefore must be revised to include the specifics on how the required two independent level indications for reduced inventory operation (as defined in GL 88-17) will be met.
c.
P1 ant' Start-up from Refueling The inspector reviewed plant startup activities during the recovery from the recent refueling outage which ended on May 3,
1993. The inspector ascertained that systems disturbed or tested
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during the refueling outage were returned to an operable status before plant startup and that plant startup, heat-up, approach to i
criticality, and core physics tests following the outage were conducted in accordance with approved procedures.
Before plant startup, the inspector performed a walk-through of appropriate l
portions of the emergency feedwater, safety injection, and EDG
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support systems disturbed during the refueling outage and independently determined that these systems were returned to service in accordance with approved procedures.
On May 1, 1993, the inspector observed activities associated with bringing the reactor critical. Specifically, the inspector witnessed partial performance of GOP-3, "heactor Startup From Hot Standby To Startup (Mode 3 To Mode 2)", Revision 8, and REP-107.003, "Beginning Of-Cycle Dilution -To-Criticality, Revision 5."
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item 3.3 of REP-107.003 section 3, entitled " Notes, Precautions and Limits", was not implemented.
Item 3.3 states: "If the count i
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of two during any increment of control bank withdrawal or during any one Inverse Count Rate Ratio (ICRR) interval during boron concentration reduction, positivo reactivity insertion shall be
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suspended until a satisfactory evaluation of the situation has been made." While at the nuclear instrumentation panel, the inspector heard the test data recorder state that the count rate had doubled.
The inspectors then examined the data recorded on REP-107.003 Attachment V.
For source range channel 31, the average of three 10 second counting periods for the ICRR interval ending at 10:02 p.m. was 220,672 counts whereas the value for the previous ICRR interval ending at 9:57 p.m. was 90,383 counts. The inspector subsequently informed the reactor engineer supervisor that the number of counts had doubled and asked if they were not required to stop the dilution when the counts had doubled. The reactor engineer supervisor discussed the subject with the test supervisor and after consulting the procedure, the dilution was stopped.
The failure to comply with step 3.3 had minor safety significance, in that, the startup rate was relatively slow, as was the rate of dilution, and that within another few minutes the dilution would have been terminated in accordance with the ICRR criterion of step 7.19.
Step 7.19 requircs the dilution be terminated when the ICRR decreases below 0.01, or is expected to be below 0.01 at the next interval. This criterion was closely monitored by the reactor engineer and test supervisors.
During subsequent discussions with the reactor engineer supervisor and the test supervisor, the inspector was informed that the data recorder had addressed his remark on doubling to the test supervisor.
The test supervisor understood that the counts had doubled; however, he failed to properly recall the associated requirement of step 3.3.
The reactor engineer supervisor also indicated that he heard that the counts had doubled and likewise failed to associate this fact with the step 3.3 requirement. The inspector was informed by Operations management that the reactor operator was unaware that the counts had doubled since the last ICRR interval.
The licensee determined that the primary contributors to the failure to comply with step 3.3 were:
(1) step 3.3 was from a previously used method to monitor approach to criticality and was no longer necessary, (2) inadequately briefed notes, precautions and limitations and, (3) the test supervisor's focus on step 7.19 ICRR criteria for dilution termination. The inspector agreed that the criteria in step 7.19 was sufficient to preclude too rapid of a startup rate. -The licensee indicated that criterion 3.3 will be removed from REP-107.003 prior to its next use. Additionally, to help focus attention on the importance of all the information in the " notes, precautions, and limits" section, the licensee was considering inclusion of a signature requirement to document that the information in this was reviewed and understood. The individuals involved with the failure to follow the procedure have been counseled on procedure compliance and training on this event will be conducted with appropriate personnel.
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This matter is identified as NCV 395/93-15-01:
Failure to comply with a procedural requirement while performing dilution to criticality. This NRC identified violation is not being cited because criteria specified in Section VII.B of the NRC Enforcement Policy were satisfied.
Review of P.EP-107.003 and GOP-3 revealed that these procedures were not developed to be used together.
GOP-3 apparently was developed to support startup during a cycle. When used with REP-107.003, a number of steps in GOP-3 were required to be marked as not applicable. Also, the limitations on PCS average temperature and pressurizer pressure were more restrict se in GOP-3 than in REP-107.003, i.e., 555 to 557 degrees F versus 553 to 558 degrees F and 2220 to 2250 psig versus 2210 to 2260 psig. The inspector noted that GOP-3, Revision 8, dated June 1989, had an obvious error in instruction 7.a, in that, it referenced instruction 2 whereas the correct reference was instruction 3.
When instruction 3 was discussed with a reactor engineer, the inspector was informed that a shutdown margin calculation was no longer performed per STP-134.001 as stated in the instruction.
Instead, the shutdown margin value was taken from a curve book table and a
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calculation would be performed only if this method indicated less than the required margin. Though this approach was technically acceptable, it was not reflected in the procedure. The inspector expressed concern to Operations management that GOP-3 had been used at least tnree times, perhaps more, without the error being corrected.
Based upon the inspector comments concerning GOP-3 and REP-107.003, Operations management indicated that the two procedures would be reviewed and revised as necessary to improve their joint utilization and individual correctness.
The inspector alsc noted differences in the reactor engineer / operations interface between the two shifts observed during the startup.
Specifically, the day shift reactor engineers communicated via one person with the control room operators; whereas, at night, the reactor engineer supervisor and test supervisor both provided direction to Operations.
Furthermore, the communications between the reactor engineers on day shift were more formalized than that observed during night shift. Day shift
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personnel routinely used repeat backs to ensure correctness of transferred information. Night shift personnel infrequently
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utilized repeat backs.
For example, the reactor engineer data recorder rarely repeated back dilution quantities he obtained from Operations.
For.the 9:12 p.m.-record, the inspector noted that
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the data recorder logged 4730 gallons of makeup when an operator had indicated that 2730 gallons had been added. While reviewing his data, the data recorder discovered his error and verified the proper value with the operator. The inspector was informed that the reactor engineers had not established in procedures a
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communications standard.
In addition, the Operations standard apparently applied only to communications internal to Operations i
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engineer and Operations management indicated that this item would i
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be reviewed and new procedures established as deemed necessary.
c.
Spurious Chlorine Monitor Alarm On May 1,1993, a chlorine alarm occurred in the makeup water
c facility. As a precautionary measure, a PA announcement was-made i
to inform site personnel of the alarm and to evacuate the area.
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After plant personnel determined that no chlorine leak was present, normal access was restored to the area. No definitive
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cause for the alarm was determined; however, it was theorized that
a slight packing leak occurreo during a valve manipulation. The
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licensee's response to the event was proper. The inspectors noted that the chlorine leak and subsequent building evacuation was not logged. This was discussed with the Shift Supervisor who agreed that this should have been logged and directed that a late log r
entry be made.
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d.
Reactor Trip Breaker Deficiency On May 1, 1993, the Reactor Trip Breakers (RTBs) were closed from the main control board in preparation for reactor startup. The
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inspector observed that while the RTB close control switch was
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being actuated, the "B" RTB green open indication extinguished and
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then immediately relit. The red breaker closed indication was not observed to light. The operating shift discussed this abnormal indication among themselves and then successfully closed the "B" RTB by actuating the main control board switch a second time.
e This item was discussed with the Shift Supervisor who indicated
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that this was a recurring problem with the "B" RTB. Furthermore, an engineering evaluation had previously determined that the failure to close was not a safety concern, i.e., the RTB safety function was to open. The inspector agreed that the safety function was to open. However, if the cause had not been conclusively determined, then it was not possible.to ensure that the malfunction would not eventually degrade the safety function.
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During the subsequent shift electricians observed the breaker locally, while it was closed from the MCB.
It was determined that
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the problem with closing observed earlier occurred because the operator did not rotate the RTB close control switch completely.
An NCV was identified for failure to comply with a procedural requirement while diluting to-criticality.
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7.
ESF System Walkdown (71710)
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The inspector verified the operability of an ESF system by performing a walkdown of the accessible portions of the RHR system. The inspectors confirmed-that the licensee's system line-up procedures matched plant
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drawings and the as-built configuration. The inspectors looked for
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equipment conditions and items that might degrade performance (hangers
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and supports were operable, housekeeping, etc.). The inspector verified that valves, including instrumentation isolation valves, were in proper position, power was available, and valves were locked as appropriate. The inspector compared both local and remote position indications.
No discrepancies were noted.
8.
Action on Previous Inspection Findings (92701 and 92702)
(Closed) Violation 395/91-10-01, Failure to follow procedure during a RHR pump test.
This violation involved test group personnel installing field standard gauges incorrectly for a RHR pump test. Test unit personnel procedural compliance and attention to detail have improved considerably since this event.
9.
Onsite Follow-up of Events at Operating Power Reactors (93702)
On April 7,1993, there was a spill of approximately 6000 gallons of chromated water from the component cooling water system, and a loss of component cooling water flow to the spent fuel pool heat exchangers for 50 minutes. The details of this event are discussed in NRC special inspection report 395/93-14.
10.
Exit Interview (30703)
The inspection scope and findings were summarized on May 12, 1993 with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed the inspection findings.
No dissenting comments were received from the licensee. The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during the inspection.
On May 27, 1993, the licensee was informed that their practice of having only one source of level. indication (tygon tubing), during certain portions of reduced inventory, did not meet the intent of GL 88-17. The licensee was requested to revise their response to GL 88-17 to include the specifics on how the. required level indication will be met for future reduced inventory operations.
Item Number Description and Reference (NCV) 93-15-01 Failure to comply with a procedural requirement during dilution to criticality (paragraph 6).
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Acronyms and Initialisms CCP Centrifugal Charging Pump CMC Coordinated Manual Control
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DP Differential Pressure DRSS Division of Radiation Safety and Safeguards ECCS Emergency Core Cooling System EDG Emergency Diesel Generator ESF Engineered Safety Feature GOP General Operating Procedure GL Generic Letter HP Health Physics ICRR Inverse Count Rate Ratio KW Kilowatt LER Licensee Event Reports MCB Hain Control Board MOVAT Motor-0perated Valve Testing MRF Modification Request Form MWR Maintenance Work Request NCV Non-Cited Violation NRC Nuclear Regulatory Com' mission i
NRR Nuclear Reactor Regulation PA Public Address PMTS Preventive Maintenance Task Sheet PTP Plant Test Procedure RCS Reactor Coolant System REP Reactor Engineering Procedure RHR Residual Heat Removal RTB Reactor Trip Breaker RWP Radiation Work Permits STP Surveillance Test Procedures TI Temporary Instruction TS Technical Specifications TSC Technical Support Center
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