IR 05000369/1993029
| ML20059G464 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 01/11/1994 |
| From: | Lesser M, Maxwell G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20059G434 | List: |
| References | |
| 50-369-93-29, 50-370-93-29, NUDOCS 9401240168 | |
| Download: ML20059G464 (13) | |
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- NUCLEAR REGULATORY COMMISSION UNITED STATES yN t
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E 101 MAR'ETTA STREET, N.W., SUITE 2900
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Report Nos. 50-369/93-29 and 50-370/93-29 Licensee:
Duke Power Company 422 South Church Street Charlotte, NC 28242-1007 P
Facility Name: McGuire Nuclear Station 1 and 2 Docket Nos. 50-369 and 50-370 License Nos. NPF-9 and NPF-17
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Inspection Conducted: November 21, 1993 - December 18, 1993
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Inspector hw
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Senior Resident Inspector r
P. Hopkins Resid t Inspector, Catawba Approvedpy b
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M.'Lester, Section Chief Date Signed Division of Reactor Projects SUMMARY Scope:
This routine, resident inspection was conducted in the areas of plant operations, surveillance testing, maintenance observations, and cold weather preparation.
Backshift inspections were performed on November 30 and December 1, 2, 3, 5, 6, 8, 10 and 14.
Results:
In the area of operations, each of the station's shift crews attended a special classroom case study concerning the August 31, 1993 steam leak event inside Unit 2 containment building. The training was considered effective in disseminating lessons learned from the event (paragraph 2.d.).
In the surveillance area, an apparent violation was identified involving operations test technicians and their supervision site procedural requirements during stroke testing of Unit I auxiliary feedwater valves (paragraph 3).
9401240168 940113 PDR ADOCK 05000369-
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In the maintenance area, an Unresolved Item was identified concerning inaccuracies in the methods used to calculate unidentified reactor coolant leakage.
This condition resulted from the plant's design and construction requiring numerous non-reactor coolant or non-CVCS drain lines. to be routed into the reactor coolant drain tank (paragraph 4.b.).
Also, a leak was identified in the Unit 2 reactor coolant drain tank system.
The-leak was from a crack in one of the tank's drain lines. The leak was repaired and the system was returned to service (paragraph 4.a.2.).
During the previous reporting period the inspectors documented a Unit 2 leak that occuried on one of the Unit 2 reactor coolant drain tank manually operated diaphragm valves.
The valve, 2WL-10, had loose bolts that connected the body to the
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bonnet (see RII Report 93-24, paragraph 2.e.).
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REPORT DETAILS l
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Persons Contacted Licensee Employees T. Arlow, Safety Review Group D. Baxter, Support Operations Manager A. Beaver, Shift Operations Manager
- R. Bostian, Mechanical Maintenance Manager J. Boyle, Work Control Superintendent R. Branch, General Supervisor, Mech. Maint.
D. Bumgardner, Unit 1 Operations Manager
- B. Caldwell, Training Manager
- M. Cash, Engineering Supervisor W. Cross, Compliance Security Specialist T. Curtis, System Engineering Manager F. Fowler, Human Resources Manager E. Geddie, Station Manager l
G. Gilbert, Safety Assurance Manager
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P. Guill, Compliance Engineer R. Hall, Engineering Manager
- B. Hamilton, Superintendent of Operations
- F. Hayes, Manager, Human Resources
- T. McMeekin, Site Vice President l.
M. Nazar, Station Manager Staff
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- R. Ovellette, Reactor Engineer
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M. Pacetti, Mechanical / Nuclear Engineer T. Pederson, Safety Review Supervisor
N. Pope, Instrument & Electrical Superintendent R. Sharpe, Regulatory Compliance Manager
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- B. Travis, Component Engineering Manager
H. Vanpeiet, Engineering i
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J. Washam, Safety Review Group
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Other licensee employees contacted included craftsmen, technicians,
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operators, mechanics, security force members, and office personnel.
NRC Resident Inspectors
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- G. Maxwell, SRI
- P. Hopkins, RI
- Attended exit interview 2.
Plant Operations (71707)
a.
Observations i
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period to verify conformance with applicable regulatory j
requirements. Control room logs, shift supervisors' logs, shift
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turnover records and equipment removal and restoration records were routinely reviewed.
Interviews were conducted with plant operations, maintenance, chemistry, health physics, and performance personnel.
Activities within the control room were monitored during shifts and at shift changes. Actions and/or activities observed were conducted as prescribed in applicable station administrative directives.
Plant tours taken during the reporting period included, but were not limited to, the turbine buildings, the auxiliary building, electrical equipment rooms, cable spreading rooms, and the station yard zone inside the protected area.
During the plant tours, ongoing activities, housekeeping, fire protection, security, equipment status and radiation control practices were observed.
b.
Unit 1 Operations The unit operated in Mode 1 at full power for this reporting period. However, on December 6, while technicians were setting up to perform a surveillance test on the turbine driven auxiliary feedwater pump, an inadvertent ESF actuation occurred. Details pertaining to this event are contained in paragraph 3.
c.
Unit 2 Operations The unit began this report period in Mode 1 at full power. On December 3 a reactor coolant system leak was identified. The leak was similar to the leak identified on November 10 because it stopped after the operators secured the reactor coolant drain tank pumps and closed the drain tank outlet isolation valve (2WL-3).
Reactor power was reduced to 15 percent so that personnel could access lower containment to locate and repair the leak. The leak was from a crack in the system piping near the weld where valve-2WL-267 connected to the waste process piping. On December 4 repairs were completed, and on December 5 the unit was returned to full power operations for the remainder of the reporting period.
Details pertaining to the reactor coolant system leak are contained in paragraph 4.a.2.
d.
Case Study Training for Plant Operators On December 2 the inspectors evaluated the training material and attended a training session on the Unit 2 steam leak of August 31, 1993. The case study was conducted at the McGuire Orerations Training Center and was provided one time each week until each of the operating crews had received it. The objective of the training included:
1) identification of potential problems with the event, 2) identification of root causes of problems that
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occurred during the event, and 3) identification of solutions or lessons learned during the event. At the end of the session the operators practiced plant cooldown from Mode 3 to Mode 4 with excess letdown in service.
The inspectors observed an open and lengthy classroom discussion
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about the steam leak that resulted from incorrectly installed kerotest valve (2CF-130) internals. Other discussions included long-tcrm corrective actions tc prevent recurrence of some of the mistakes that led up to and were made during the event.
This training was executed in a professional manner and provided a.
good opportunity for operators to learn from mistakes that had been made. This case study training session was developed and implemented as part of the long-term corrective action recommended -
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in response to the LER associated with the Unit 2 steam leak (370/LER 93-06).
No violations or deviations were identified.
3.
Surveillance Testing (61726)
Observed Surveillance Tests Resident inspectors reviewed and\\or witnessed selected j
surveillance tests to assess the adequacy of procedures and performance as well as conformance with the applicable TS.
Selected tests were witnessed to verify that (1) approved procedures were available and in use, (2) test equipment in use i
was calibrated, (3) test prerequisites were met, (4) system-J restoration was completed, and (5) acceptance criteria were met.
The following test was reviewed in detail:
ESF Actuation While Conducting PT/1/A/4252/03B, CA Train B
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Valve Stroke Timing-Quarterly Turbine Driven Flowpath On December 6, 1993, at 10:30 a.m., while operating in Mode 1 at 100 percent power, Unit 1 experienced an inadvertent actuation when the turbine driven auxiliary feedwater system pump automatically started. Operations personnel were performing a valve stroke timing test for valve ICA-488, CA pump number 1 to steam generator IC control, as is required i
by procedure PT/1/A/4252/03B, CA Train B Valve Stroke Timing I
- Quarterly (TD Pump Flowpath). While performing the test, operations technician A was placing a jumper on terminal B-21R in the CA pump 1B control panel. Technician A inadvertently placed the jumper on terminal B-22R directly.
i below terminal B-21R. When the jumper was placed on terminal B-22R, a path to ground was created and the control power fuses for the associated valves were blown.
Loss of
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control power to Valve ICA-48B caused it to fail safe to open, subsequently allowing steam flow to the TDCA pump, which operated as designed.
The inspectors reviewed the details of the event. At.10:30 a.m., OPS technicians were performing PT/1/A/4252/03B when OPS test technician A had installed a threaded banana clip
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connector on terminal 3-21L. Test technician B then independently verified that the banana clip connector was on terminal B-21L. OPS test technician A then attempted to install a special jumper, which had a switch located in its circuit, to terminal B-21R. Because of the presence of two permanently installed wires and associated nuts on terminal B-21R, test technician A was unable to install the recommended banana clip connector on the terminal and was instead using an adaptor with an alligator clip connector for that connection. The inspectors observed that the referenced procedure contained a note stating that the special switched jumper with alligator clip connectors would be needed to safely time valve ICA-48. Steps 12.3.8, 12.4.8 and 12.5.8 of the same procedure state: " Ensure that approved screw on safety insulated connectors are used on all applicable jumper work. Do NOT use alligator clip jumpers unless accompanied by appropriate supervision."
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This procedure step had been signed off by OPS technicians, even though no supervisory personnel were present at either test.
The inspectors evaluated the completed test results, and on December 13, interviewed the test and supervisory
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personnel who stated that supervisory personnel typically were not present when alligator clips were used during this test.
OPS test technician A verified the position of terminal B-21R. Test technician B then independently verified the position of terminal B-21R. OPS test technician A then started to make the connection. The inspectors determined that the OPS test technician A hesitated before making the connection, pulled the rubber boot back on the alligator clip, and then pro'ceeded to attempt to make the connection.
An inadvertent connection was apparently made to terminal B-22R, which was directly below the intended connection point, thereby grounding the circuit. Upon the inadvertent contact the OPS test technicians reported hearing the sound of valves cycling and the turbine driven auxiliary feedwater pump starting. OPS test technician A removed the jumper and left the control panel.
Operations Control Room (CR) personnel observed the automatic start of the turbine driven auxiliary feedwater pump and the movement of the control valves to their open position. Attempts to regain control of the pump or valves by CR personnel were unsuccessful. The main
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turbine / generator load was reduced by eight MWe to compensate for the cooldown caused by the auxiliary feedwater injection. The turbine driven pump was then tripped manually. After the pump was tripped the turbine / generator load was returned to normal. The plant staff initiated an investigation of the cause of the automatic start under Work Order 93087884.
Subsequently, I&E personnel discovered that fuses BA-1 and BA-2 in terminal board 601 were blown. The blown fuses _had deenergized control power from the associated control valves and caused them to fail open, which in turn caused the automatic start of the turbine driven pump. Also, since the control power had failed, the steam generator blowdown (BB)
containment isolation valves had not closed. The fuses were replaced and the BB containment isolation valves isolated as required.
The BB valves and turbine driven pump were then realigned by operations control room personnel.
The cause of the blown fuses was a short to ground during the performance of the valve stroke timing test.
The inspectors determined, as a result of the reviews associated with this event, that the following items appear to be examples of a failure to follow procedures:
1.
On December 6, 1993, the operations technicians safety system's test team failed to-adequately implement McGuire Nuclear Station Directive 704.5-6,- Management Procedure 1-6, and PT/1/A/4252/03B.
The technicians failed to properly and independently verify the placement of an alligator clip on electrical terminal B-21R, located in the Unit I auxiliary feedwater pump room CA pump 1B control panel. This resulted in an ESF actuation of the auxiliary feedwater system.
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On December 6, 1993, operations test technicians,
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while performing PT/1/A/4252/03B, failed to verify before signing off steps 12.3.8, 12.4.8 and 12.5.8, that appropriate supervision personnel were present before they used alligator clips.
Interviews with the technicians involved revealed that supervisory personnel were not present.
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On December 6, 1993 after the attempt to perienn PT/1/A/4252/03B that had aiready resulted in an ESF actuation, the technician notified supervision prior.
to using alligator clips as part of the test procedure. The supervisor did not go to the work site as required by procedur.
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This issue will be identified as an Apparent Violation, 50-369,370/93-29-01: Test personnel failing to follow procedure.
Presently, a Notice of Violation is not being sent pending further NRC review.
One apparent violation was identified.
4.
Maintenance Observations (62703)
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Observation
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Resident Inspectors reviewed and/or witnessed routine maintenance activities to assess procedural and performance adequacy and conformance with the applicable TS.
The activities witnessed were examined to verify that, where applicable, approved procedures were available and in use, prerequisites were met, equipment restoration was completed, and maintenance results were adequate.
The following maintenance activities were reviewed or witnessed in detail:
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Repair The Power Range Channel Deviation Alarm (N44), (WO 93085681)
The inspectors verified the following by direct observation, document review, and by personnel interviews, technician and management interface.
On November 24, 1993, a power range channel deviation alarm occurred in the control room.
Operations properly verified Power Range and flux conditions on the OAC. No other necessary actions were required. A Work _ Order 93085681 was initiated to troubleshoot and repair the N44 power range channel.
I&E shift personnel determined, after initial troubleshooting, that a bad isolation amplifier (NM305) was probably the cause of the alarm.
I&E technicians discussed this finding with operations, and a decision was made to place the comparator channel defeat switch to the " Defeat N44" position. This defeats the N44 channel and allows the alarm to come in again from other power range channels.
On November 29, 1993, W0 #93085681 was assigned to two qualified technicians on the responsible crew. The technicians completed sections 10.1, 10.4, 10.5 and 10.9 of IP/0/A/3207/03K to place power range channel N44 in test, verify the condition of the defective isolation amplifier NM305, and test the new amplifier. The new amplifier was installed using IP/0/A/3090/02, Instrument and Electrical Troubleshooting procedure. While performing section 10.5 of IP/0/A/3207/03K (Isolation Amplifier Checkout) a few
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resolved by the responsible component engineer, who decided
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to conservatively verify correct summing-and level amplifier operation by performing section 10.4 of the procedure.
These concerns were also resolved by I&E procedure group personnel, and appropriate changes to the procedure were initiated. The procedural changes were of a clarifying
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l During performance of IP/0/A/3207/03K, the technicians also noted that'the " Overpower Rod Stop" bistable (NC-302) and Axial Flux Difference (AFD) meters were adjusted and the control room SR0 was notified appropriately.
The inspector then witnessed the verification of Power Range Channel N44, which was performed using PT/0/A/4600/14G, and QC notification for performance of an "after job" inspection per work order.
Power Range Channel N44 was then returned to service and removed from the TS logbook by the control room SRO. All actions were appropriately documented on the Work Management System. Technical Specifications sections that were referenced durir.g repair / calibration included 3/4.3.1, LC0 3.3.1, and Table 3.3-1, Action Statement 2.a.
The maintenance technician's actions were appropriate, and the correct procedures and equipment were used.
2.
Unit 2 Reactor Coolant Leak, locate the Leak, Repair the l
Leak, and Return to Power (WO 93087561)
On December 3, Unit 2 operations personnel determined that reactor coolant was leaking from the reactor coolant drain tank or from the piping associated with the tank. The leak was isolated by the operators when they secured the reactor coolant drain tank pumps and closed the tank's isolation valve, 2WL-3.
Reactor power was reduced to 15% to allow personnel to enter the containment building to locate the source of the leak. The inspectors accompanied the plant staff during one of the containment entries.
Initially, the inspectors and the plant staff anticipated that the leak may have been coming from the bonnet section of one of the system's Grinnell diaphragm-operated valves. After power was reduced, a close inspection of the valves suspected of leaking was conducted. None of the diaphragm-operated valves displayed any indication of leakage. The piping associated with the drain tank was inspected and a crack was found in the piping near a pipe weld that connected the system piping to valve 2WL-267. The inspectors referred to the FSAR Figure 11-2 and noted that 2WL-267 was a drain valve connected to the four-inch piping located downstream
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of valve 2WL-3. A review of the' circumstances and conditions leading up to this most recent leak indicates that the crack occurred in the heat-affected area of the weld and not in the weld material. The plant staff considered several causative factors. The first factor was identified as mild water hammer (steam void collapsing) in the piping from the reactor coolant drain lines (C and D).
The second factor applied to the heat-affected section of the weld and indicated that perhaps the incorrect heat range for the weld was used during construction.
The inspectors reviewed the minor modification (MM 3874) and work order (WO 93087561), which was implemented to isolate-and repair the leak.
The records indicated and the
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inspectors verified that valve 2WL-267 was removed from the four-inch piping downstream of 2WL-3. The piping between
the four-inch line and the valve was capped and welded. The weld was visually tested using liquid penetrant and inspected The system then was returned to service.
The mild water hammer was reported to have occurred in this portion of the reactor coolant drain tank pump suction header, on previous occasions. On those instances, temperature readings on all four reactor coolant crossover drain lines indicated that two of the four (C and D) had valve leakage. The other two lines (A and B) measured 110*F or lower. The two valves associated with the leaks were two inch Kerotest packless globe valves. These leaky valves were not trended for leakage and the identification of repair needs was not reported to management.
The inspectors determined that System Engineering has developed a pro-active program for monitoring primary system drain valve leakage and verifying that required corrective maintenance is completed as appropriate.
Problem Investigation Process Report PIP-2-M93-1239 was written by the plant staff to ensure that short-term and long term corrective action is satisfactorily completed. On December 5 the system was returned to~ service and the plant was returned to full power.
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Non-Conservatism in Reactor Coolant Leakage Monitoring - Units 1 i
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and 2 The inspectors reviewed an operations Special Order 93-17, dated December 8,1993, for calculations of reactor coolant unidentified leakage. The inspectors reviewed NUREG-1107, A User's Guide, entitled "RCSLK9:
Reactor Coolant System Leak Rate Determination For PWRs." Paragraph 3.2 of the NUREG specifically alerts the user about what must be done to accurately determine the-identified leak rate for the reactor coolant system and the
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charging system during the test, which is the amount of water collected in both the pressurizer relief tank and the reactor coolant drain tank.
It warns the user that no drains, other than the reactor coolant and charging system drains, may be allowed to collect in the reactor coolant drain tank while the identified leakage rate is being calculated.
If the warning is not adhered to, the identified leak rate could be too large and, therefore, mask the actual unidentified rate.
The inspectors interacted with numerous members of the plant staff concerning Special Order 93-17 and reviewed Figure 11-2 in the FSAR to determine what lines feed into the reactor coolant drain tank. The plant staff recognized that 78 lines fed into the reactor coolant drain tank and that these lines could not be remotely isolated from the tank to obtain an accurate calculation of the identified leakage.
After the condition was identified, operations ordered through this Special Order that until further notice total leakage would be considered unidentified and the TS limit of one gallon per minute would be in effect.
Engineering wrote temporary modifications for both units to locate
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and permanently remove 26 of the lines feoding into each of the unit's reactor coolant drain tank. Work Orders WO-93089150 and WO 93089055 were issued for the removal of these drain lines and the temporary drainage of them into the containment floor / sump. Those lines, each one a leak-off from the safety injection system, were removed between December 10 and 13, 1993. During the inspection and removal of the lines the inspectors observed the following work activities: 1) locating the lines, 2) crimping the lines, and i
3) removing and capping them.
The temporary modifications (U-l 6315 and U-2 6314) required that the lines to be permanently re-
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routed during the next scheduled unit refueling outages.
During the week of December 13, the inspectors observed the calculations of reactor coolant leakage after the 26 lines had been removed.
Some slight increase in the calculated unidentified leakage rate was observed, but it remained below the one gallon-per-minute TS limit.
The plant staff has documented this inadequacy of the reactor coolant leakage monitoring system on a Problem Investigation _
Process form, PIP 0-M93-1253.
Sufficient information was not available to determine if the unidentified leakage -rates for past calculations had exceeded the TS limit of one gallon per minute.
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This condition will be identified as an Unresolved Item, 50-369,370/93-29-02, Calculating the unidentified reactor coolant
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5.
Cold Weather Preparations (71714)
The inspectors conducted a review of licensee cold weather preparations to verify that the licensee maintained effective implementation and the cold weather protection program of protective measures for extreme cold weather.
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The inspectors observed that the licensee, with the.use of PT/0/13/4700/21, Plant Heating Water System Checkout and Startup, and PT/0/B/4700/38, Verification of Freeze Protection Equipment and Systems,
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had indeed inspected systems susceptible to freezing.
Some of the-piping, systems and components observed by the inspectors included the refueling water storage tanks, low voltage switchyard circuits, and service water lines. The inspectors verified-by review and observation that heat tracing, space heaters, weather curtains and/or insulation had been installed.
Inspectors witnessed the proper setting of thermostats, heat tracing circuits and space heating circuits. The inspectors also verified that protective measures had been' reestablished for systems that required them and that had been subjected to maintenance or modification during the previous year. The licensee also had procedures for long shutdown periods to ensure that an area no longer kept warm by normal plant operations would be adequately protected from cold.
No violations or deviations were identified.
6.
Exit Interview (30703)
The inspection scope and findings identified below were summarized on December 22, 1993, with members of the Station Manager's staff. The following items were discussed in detail:
Apparent Violation, 50-369,370/93-29-01: Test personnel failing to follow procedure (paragraph 3).
Unresolved Item, 50-369,370/93-29-02, Calculating the unidentified reactor coolant leak rate (paragraph 4.b.).
The licensee representatives present offered no dissenting comments, nor did they identify as proprietary any of the information reviewed by the inspectors during the course of their inspection.
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Acronyms and Abbreviations CR
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Control Room CVCS -
Chemical and Volume Control System ESF-
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Engineered Safety Features GPM
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Gallons Per Minute I&E
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Instrumentation and Electrical LER
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Licensee Event Report MWe
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Mega-Watt Electric NC
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Reactor Coolant System NCDT -
Reactor Coolant Drain Tank
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Safety Injection System NRC
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Nuclear Regulatory Commission OAC
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Operator Aid Computer
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Operations OPS
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RI
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Resident Inspector
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SR0 Senior Reactor Engineer
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TS
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Technical Specification
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UNR Unresolved Item
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Violation VIO
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