IR 05000369/1987021
| ML20237L158 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 08/13/1987 |
| From: | Guenther S, William Orders, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20237L098 | List: |
| References | |
| 50-369-87-21, 50-370-87-21, NUDOCS 8708270440 | |
| Download: ML20237L158 (12) | |
Text
$8 880u, UNITED STATES NUCLEAR REGULATORY COMMISSION
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,j 101 MARIETTA STREET.N.W.
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ATLANTA, GEORGI A 30323
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o 9.....s Report Nos.:
50-369/87-21 and 50-370/87-21 Licensee:
Duke Power Company 422 South Church Street Charlotte, NC 28242 Facility Name:
McGuire Nuclear Station 1 and 2 Docket Nos.:
50-369 and 50-370 License Nos.:
NPF-9 and NPF-17 Inspection Conducted: June 21, 1987 - July 31, 1987 Inspectors:
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W.~0 rs, Senior R sident Inspector Dat'e Signed d4 12,11f 7 WTA
S. Guenther, Resident Inspector Date Signed 7-/ f - 7 ~7 Approved by:
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x T. A. Peebles',' S~ection Chief Date Signed Division of Reactor Projects SUMMARY Scope: This routine unannounced inspection involved the areas of operations, safety verification, surveillance testing, maintenance activities, Licensee Event Report followup and the Unit 2 post-refueling startup.
Results:
In the areas inspected, one violation with multiple examples was identified.
8708270440 870814 PDR ADOCK 05000369
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l-REPORT DETAILS 1.
Persons Contacted Licensee Employees i
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T. McConnell, Plant Manager B. Travis, Superintendent of Operation 5 D. Rains, Superintendent of Maintenance
- B. Hamilton, Superintendent of Technical Services N. McCraw, Compliance Engineer M. Sample, Superintendent of Integrated Scheduling
- N. Atherton, Compliance-
- G. Gilbert, Operations Engineer
- A. L. Beaver, Operations Engineer
- S. E. Leroy, Licensing, General Office
- R. D. Brooke, Integrated Scheduling
- M. D. Kimray, Integrated Scheduling
- K. R Frye, Mechanical Maintenance
- P. B. Nardoci, Licensing Engineer Other licensee employees contacted included ennstruction craftsmen, technicians, operators, mechanics, security force members, and c:ffice personnel.
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on August 7, 1987,-with those persons indicated in paragraph 1 above.
One procedural violation, consisting of three examples, was discussed; the licensee offered no dissenting comments.
An unresolved item concerning slave relay testing and an inspector followup item involving an inadvertent safety injection were also discussed. The licensee did not identify as proprietary any of the information reviewed by the inspectors during the course of their inspection.
3.
Unresolved Items An unresolved item (UNR) is a matter about which more information is required to determine whether it is acceptable or may involve a violation
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or deviation.
One unresolved item concerning Unit 1 slave relay testing is discussed in the surveillance testing section of this report.
4.
Plant Operations
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The inspection staff reviewed plant operations during the report period to verify conformance with applicable regulatory requirements. Control room logs, shift supervisors' logs, shift turnover records and equipment
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I removal and restoration records were routinely perused.
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.
The
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complement of licensed personnel on each shift met or exceeded the minimum required by Technical Specifications.
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plant tours taken during the reporting period included, but were not limited to, the turbine buildings, Unit 2 reactor building, auxiliary building, Units 1 and 2 electrical equipment rooms, Units 1 and 2 cable spreading rooms, and the station yard zone inside the protected area.
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During the plant tours, ongoing activities, housekeeping, security, equipment status and radiation control practices were observed.
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Unit 1 Operations Unit 1 operated at, or near, rated powar for the entire reporting
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period.
No major operating problems we e encountered.
An engineered safety features (ESi) actuation occurred on July 9 during the performance of slave relay tasting.
The details surrounding this incident are discussed in the surveillance section of this report, b.
Unit 2 Operations Unit 2 began the reporting period in Mode 5 (cold shutdown),
undergoing the final stages of a refueling outage begun on May 1, 1987. Most of the outage had proceeded ahead of schedule, however, several emergent problems with motor operated valves / actuators caused-delays in the plant's heatup to Mode 4 (hot shutdown)
Mode 4 was entered early on June 30, with subsequent heatup to Mede 3 (hot standby) following on July 1.
The reactor was taken critical for zero power physics testing at 8:40 p.m.,
on July 3; Mode 1 (power)
operation commenced at 9:43 p.m., on July 5, and the unit was placed on line at 11:41 p.m. that night.
It is worth noting that the end-of-cycle (EOC)-1 and E0C-2 refueling outages on Unit 2, which were scheduled for 62 rnd 63 days,
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respectively, both significantly exceeded the rp'ected datos, c
running 104 and 105 days respectively.
The just i:ompleted EOC-3 outage was scheduled for, and completed in, 65 days and the unit has run smoothly with no significant operating problems of ten encountered after a restart from a major outage.
(1)
Inadvertent Safety Injection Unit 2 was in Mode 4 at 8: 39 a.m.,
on July 1, when a valve misalignment resulted in an inadvertent injection of water into the reactor coolant (NC) system cold legs from the
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refueling water storage tank using the 2A safety injection
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J (NI) pump.
The control room operator was in the process of restoring the NI system to standby readiness. after having completed NC pressure isolation valve leak rate testing in-accordance with performance test procedure PT/2/A/4200/088.
Valve 2NI-118, the train A cold leg isolatior. valve, was opened while the 2A NI pump was still operating in recirculation.
L The operator immediately recognized his error and closed.2NI-118 and secured the NI pump. to terminate the injection.
The cold leg _ injection check valves were subsequently retested to. verify proper seating.
The licensee has initiated a Problem Investigation Report (PIR
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Serial No. 2-M87-0151)' to determine the cause.of the' incident and appropriate corrective actions. This issue will be tracked as an Inspector Followup Item (IFI-50-370/87-21-01) pending.
q completion and review of.the. licensee's investigation, j
i (2) Reactor Trip Breaker Failure j
I During control. rod drop testing on the night of July 2, the operators observed that the rod control demand counter was not indicating properly so all rods-were ' inserted while investigating the problem.
During their investigation, the
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operators detected smoke in the area of the reactor trip breaker cubicles, located adjacent to the rod control cabinets. The reactor trip breakers were immediately tripped from the control room and the breaker open position. indicators (green lights)
were verified to be illuminated. Further investigation for the source of the smoke revealed that reactor trip breaker B-(RTB-B) had, in actuality, not tripped.
Several attempts were made to trip the breaker locally prior to its opening while manually tensioning the closing spring.
A preliminary investigation of the breaker failure by licensee personnel.and an NRC Augmented Inspection Team (AIT) revealed that mechanical binding had prevented the breaker from opening.
The smoke that was observed near the breaker was caused by the breaker shunt trip coil which burned up in the attempt to open i
the bound breaker.
The details surrounding this investigation and AIT inspection are discussed in NRC Inspection Report Nos.
50-369, 370/87-22.
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On July 3, the failed reatetor trip breaker was replaced with
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a reactor trip bypass breaker from Unit 1 and all four breakers
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(two main trip breakers and two bypass breakers) were functionally tested prior to resuming the plant startup.
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(3) Steam Generator Feedwater Inlet Check Valve Bypass ~ Misalignment Each McGuire Steam Generator (SG) is equipped with a main and an auxiliary feedwater nozzle for use above and below 17 percent I
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of rated feedwater flow, respectively.
Before transferring feedwater. flow from the. auxiliary nozzle to the main nozzle,
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cold water must be purged from the main feedwater line to'
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minimize.the thermal transient. This is accomplished as part of
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the power escalation / operation procedure (OP/2/A/6100/03). by
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allowing a controlled rate of hot water to flow out of the main feedwater nozzle in. the reverse direction, around the'
containment check valve through a one-inch bypass l'.ne, through-the feedwater isolation - bypass valve, and back. to the main condenser. When the computer points which monitor the feedwater containment isolation valve line-temperatures reach a minimum of 250 degrees Fahrenheit, normal'feedwater flow can be established through.the main feedwater nozzles.
During the Unit 2 startup on July 2, 1987, the operators attempted to establish the reverse purge flow as described abov6 by : implementing OP/2/A/6100/03, but the feedwater
containment isolation valve line temperatures failed to respond.
The operators verified-the alignment of valves outside containment to be correct and concluded that 'normally. open manual valves 2CF-179, 180, 181.' and 182, located in the one-inch bypass lines around the containment check valves, must have been closed.
Verifying anc', if necessary, correcting the valve positions would require a containment entry so power was reduced to approximately :10 percent of rated.
The operators' suspicions were confirmed and the four manual valves were opened allowing the establishment of reverse purge feedwater flow and the resumption of the power escalation.
Valves 2CF-179,180,181 and 182 are normally aligned in the open position by OP/2/A/6250/01, " Condensate and Feedwater System".
The valve checklist of that procedure was last completed on October 3,1985.
The repositioning of any valve from its normal position is only authorized as part of an approved procedure or through the implementation of the removal and restoration (R&R) procedure (OP/0/A/6100/09).
No active R&R's covering the valves in question were outstanding at the i
time of the incident.
Discussions with the Operations Staff and a review of plant procedures revealed that 2CF-179, 180, 181 and 182 are contained in Enclosure 13.1, the containment integrity penetration
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checkli st, of PT/2/A/4200/020, the " Containment Integrity Verification During Core Alterations" performance test. These
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valves form part of the inside containment ; solation boundary L
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for penetration numbers M-153, M-262, M-308 and M-440, l
respectively. The procedure requires each penetration listed in Enclosure 13.1 to be either in service (i.e., carrying flow cr fluid-filled), isolated with either ' the inside or outside penetration isolation valves closed, or isolated with a completed Penetration Isolation Verification Sheet (Enclosure 13.2).
Step 12.2.1.4 of the PT requires that any manual valve that must be physically closed to isolate. a penetration be documented on Enclosure 13.7,
"Menual Valves Closed for Containment Integrity Verification".
Copies of Enclosure 13.7 are to be routed b the Unit Coordinator for disposition.
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A review of the plant master files revealed that PT/2/A/4200/02C had been implemented three times during the Unit 2 EOC-3 refueling outage.
The first time was in preparation for core off-load early in May.
All four penetrations in question were in service at that time and no valves were closed. The PT was
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run a second time between May 31 and June 2 in preparation for l
core reload.
The completed Enclosure 13.1 indicates that i
penetrations M-153, M-262 and M-440 were isolated at that time by having their inside isolation valves (including 2CF-179,180 and 182) in the closed position. During its third execution on June 7-8, all four penetrations were documented as having their inside isolation valves closed.
A review of the files and discussions with the Unit Coordinator
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indicated that none of the manual valve manipulations that J
resulted in 2CF-179, 180, 181 and 182 being closed were
documented by completing Enclosure 13.7 of the PT.
Consequently, the valves were not returned to their normal open positions prior to the Unit 2 startup.
This necessitated a reduction in reactor power and a personnel entry into lower containment to reopen the mispositioned valves.
This failure to properly implement PT/2/A/4200/02C is identified
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as one example of apparent violation 50-370/87-21-02 against Technical Specification 6.8.1.
Two additional examples are discussed elsewhere in this report.
5.
Surveillance Testing Selected surveillance tests were analyzed and/or witnessed by the inspector to ascertain procedural and performance adquacy and conformance with applicable Technical Specifications.
Selected tests were witnessed to ascertain that current written approved procedures were available and in use, that test equipment in use was calibrated, that test prerequisites were met, that system restoration was completed and te.st results were adequate.
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Detailed below are selected tests which were either reviewed or witnessed:
IP/0/A/2207/02K Nuclear Instruma.ntation System (NIS) ' Intermediate Range Drawer Calibration PT/1/A/4601/03 Protective System Channel 3 Functional Test PT/0/A/4700/28 Neutron Noise Data Acquisition IP/0/A/3207/03K NIS Power Range Drawer Calibration
PT/1/A/4201/01 Containment Sump Recirculation ESF Analog Channel Operational Test PT/2/A/4200/02C Containment Integrity Verification During Core Alterations Fi/1/A/4403/08 RN Tr ain 18 Flow Balance Test IP/0/A/3002/01 Mait l'eedwater Flow Calibration a.
' Inadvertent ESF Actuation
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Unit I was - operating normally at full power on July 9,1987, with
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slave relay testing in progress in accordance with performance test i
PT/1/A/4200/28. The test had been coordinated to fulfill both the slave relay and the. lA emergency diesel generator performance /_-
operability requirements. Section 12.23 of the PT tests the proper functioning of the train "A" safety injection slave relay (K608) and causes the 1A diesel generator to start.
Prior to energizing the K608 output relay in_ the safeguards test cabinet, the associated diesel generator load sequencer must be placed in test using a keylock switch located on the load sequencer cabinet. The key must be turned clockwise, against spring pressure, to activate the test circuitry and then released to return to the normal position.
The test circuitry acts to prevent the train "A" ESF loads from actusily starting when the slave relay is energized.
On July 9, a partial train "A" engineered safeguards load sequencer actuation occurred when the associated slave relay (K608) was energized.
The train "A" decay heat removal (ND), safety injection (NI), auxiliary feedwater (CA) and control room chiller (VC) started i
on their normal power supplies; the 1A diesel generator started as required and remained unloaded.
No ESF valves realigned and no safety injection or plant transient occurred. All safety systems appeared to function normally under the. existing plant conditions.
In the initial evaluation of the event, the licensee believed that the load sequencer was not actually in test when the K608 relay was energized. This could have been caused by either an operator error in manipulation of the sequencer test switch (i.e., not rotating the switch fully clockwise or not holding the switch long enough to seal in) or ~ by a malfunctics in the test circuitry.
A Droblem Investigation Report (Serial No. 1-M87-0154) was initiated to determine the root cause~ of the ESF actuation and the appropriate corrective action =_ - _ - __ --.
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'On July 11, the applicable portions of the PT were rerun without
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incident.
The licensee had added a step to the procedure to.
independently verify. that the control room alarm generated when the
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load ' sequencer is placed in test remains sealed in. -This event will be classified 'as an Unresolved Item (UNR -50-369/87-21-03)' pending j
completion of the licensee's investigation and confirmation that the -
event was caused by a personnel / procedural problem rather than an'
equipment-failure.
6.
Maintenance Observations Routine maintenance activities were reviewed and/or witnessed by the resident inspection staff to ascertain procedural and performance adequacy and conformance with applicable Technical Specifications.
.The selected activities witnessed were examined to ascertain that, where applicable, current written approved procedures were available and in use, that prerequisites were met, that equipment restoration was completed and maintenance results were adequate.
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Licensee Event Report (LER) Followup u
In LER 369/86-20, the' licensee relays that on October 28, 1986, the i"
charging line outside containment isolation valves for both Units.were declared inoperable, rendering both trains of the' emergency core cooling system- (ECCS) inoperable.
The valves were determined to be inoperable
because of the uncertainty of the output torque capability 'of the. Rotork-motor operators installed on the valves.
The uncertainty was discovered when testing at Catawba Nuclear Station revealed the actual' torque output
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of a Rotork motor operator did not correspond to the expected torque output when the torque switches were set at less than 100 percent of the rated operator torque output. With both trains of the ECCS inoperable, both units were shut down.
Corrective actions were taken for each individual valve affected and both units were placed back in service.
Unit I was at 100 percent power and Unit 2 was at 47 percent power at the i
time of the discovery.
l This incident was attributed to a manufacturing deficiency because the Rotork torque switch setting curve did not represent actual motor operator performance.
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The LER states that bench testing by Duke Power Company (DPC) verified
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that the motor operators were capable of providing the rated torque at the i
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maximum setting.
This statement is inaccurate.
Bench testing revealed, in fact, that some motor operators would not deliver rated torques.
Based on this ard other inaccuracies, the Senior Resident Inspector contacted the appropriate licensee personnel, who agreed that the LER was
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deficient'and a revision would be issued.
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Unit 2 Startup from Refueling (71711)
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Inspections were performed to ascertain whether systems disturbed or
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tested during the refueling outage were returned to an operable status before plant startup. The plant startup, heatup, approach to criticality and core physics tests following the outage were monitored to ascertain
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compliance with approved plant procedures and the plant's Technical l
Specifications.
Walkthroughs of selected systems disturbed during the refueling outage were performed to ascertain that they were returned to service in accordance with approved procedures.
Appropriate portions of the following systems were inspected to assure conformance with the associated procedure:
OP/2/A/6350/02 Diesel Generator
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OP/0/A/6350/01 Normal Power Checklist
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OP/0/A/6350/01A 125VCC/120VAC Instrument and Control power System
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OP/2/A/6400/06 Nuclear Service Water System
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On the afternoon of June 29, the resident inspectors conducted a cleanliness inspection of the Unit 2 upper containment to verify that no
loose debris was present which could be transported to the containment sump and cause restriction of the emergency core cooling pumps' suction during accident conditions.
The following cleanliness and material deficiencies were identified and related to plant management for
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I resolution / correction:
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Several unterminated cables in the containment air return (VX) fan c
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pit were tied to a safety-related cable tray for support.
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An electrical grounding cable in the VX fan pit was not properly secured.
c)
Several pieces of trash and debris were found in the VX fan pit.
d)
The personnel hatch (submarine) between upper and lower containment was not dogged / latched closed.
The hatch was found with an intact tamper seal, however, it could be lifted open without having to rotate the handwheel.
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The ventilation filters on top of two steam generator enclosures were extremely dirty; one set appeared to have collapsed.
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There was a glycol leak in the upper ice condenser.
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An aluminum cheater bar, a step ladder with aluminum rungs, a motor and other material had been left in the upper ice condenser.
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The valve supplying instrument air to the actuator for valve 2NF-233 was leaking and had been wrapped with masking tape.
On June 30, the inspector noted a control room log entry stati' g that n
2NF-233 had failed closed (shortly after the inspectors' tour).
On July 1, a similar inspection was conducted in the Unit 2 lower containment.
Once again, several deficiencies were noted, as follows:
1)
Several towels / rags were found in the containment pipe chase.
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A segment of reactor coolant pump thermal insulation was found to be dislodged.
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A section of rubber hose used for temporary service during the outage had not been removec.
As noted in the Unit 2 operations discussion, the plant entered Mode 4 on the morning of June 30.
The heatup from Mode 5 into Mode 4 invoked numerous Technical Specification (TS) limiting condition for operation (LCO) and Surveillance requirements which were not applicable at the lower temperature; the emergency core cooling system (ECCS) (TS 3/4.5.3) and upper-lower containment personnel hatch (TS 3/4.6.5.5) specifications are two examples.
TS 3/4.5.3 requires that a minimum of one ECCS subsystem be demonstrated operable per the applicable requirements of TS 4.5.2 prior to entry into Mode 4.
TS 4.5.2.C states that this operability demonstration shall include a visual inspection which verifies that no loose debris (rags, trash, clothing, etc.) is present in the containment which could be transported to the containment sump and cause restriction of the pump suctions during accident conditions.
This visual inspection shall be performed for all accessible areas of the containment prior to establishing containment integrity pursuant to TS 3.6.1.1 (required in Modes 1-4).
TS 4.5.2.C and 4.5.3.1 are implemented at McGuire Unit 2 by completing PT/2/A/4600/03F, " Containment Cleanliness Inspection", prior to entry into Mode 4.
This PT lists plastic, cloth, rubber, paper, canvas and hoses as examples of unacceptable materials which must be removed from containment.
Any material which is determined not to pose a problem with ECCS pump suction, but is not part of installed equipment, must be logged on Enclosure 13.1 to the procedure and evaluated by the Unit Coordinator to j
determine if it may remain inside containment.
PT/2/A/4600/03F was performed cetween June 24 and June 27, 1987 and verified complete, indicating that the acceptance criteria had been met, on June 29. Any containnsnt entries made while in Mode 4 or above are controlled by Station Directive (SD) 3.1.8, " Access to Containment".
A Containment Closeout Checksheet (Attachment No. I to the SD) is to be l
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entries and to verify that no loose debris 1s-left in the areas entered,
-thereby maintaining the previously ' established level of containment cleanliness.
' Deficiencies (c), (g),- (i) and '(k) identified by the resident inspectors indicate that the licensee had failed to adequately establish and maintain upper and lower containment cleanliness pursuant. to.the TS/ procedural requirements. -This is considered to constitute a second example of the
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apparent TS 6.8.1 violation (50-370/87-21-02) discussed earlier in this report.
Finding (d) identified above, generated additional concerns with regard to containment system operability and TS compliance.
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TS 3/4.6.5.5 requires that the personnel access door between' the
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containment's upper and lower compartments be' operable and closed in Modes
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1-4.
This ensures that a minimum bypass steam flow will. occur from the lower to the upper containment compartments 'during a loss. of coolant accident (LOCA)..This' condition ensures that a diversion of the steam through the ice condenser bays is consistent with the LOCA analyses.- The associated surveillance requirement' to visually inspect and verify proper closure of the personnel access door prior to increasing reactor coolant system average temperature above 200 degrees Fahrenheit, is implemented by PT/0/A/4200/04, " Divider Barrier Hatch Seal Inspection".
That PT was' performed on the Unit 2 personnel hatch on June 27, under Work Request No. 73967. An-associated Technical Specification Action Item Log -
(TSAIL) entry (#13512) regarding operability of the hatch was cleared at 6:09 p.m., on June 27, indicating that the hatch was " closed and' sealed".
Additionally, Step 44 of the Mode L4 checklist (i.e., Enclosure 4.1 of.
OP/2/A/6100/01, the " Controlling Procedure for Unit Startup" was initialed as complete on June 28.
When the inspectors found the personnel hatch open on the afternoon of June 29, the unit was still in Mode 5 (below 200 degrees F) and the containment divider barrier was not yet required to be operable. The inspectors promptly informed the licensee of their finding, realizfng that entry into Mode 4 was imminent and that operability of the hatch would be-required.
Based upon the existing documentation available to the operations staff that the hatch was already closed and sealed, it is open to question whether the security of the hatch would have been reverified prior to entering Mode.4 at 7:08 a.m. the next morning. Heating the plant above 200 degrees Fahrenheit with the hatch in the as found condition, would have constituted a violation of TS 3.6.5.5.
A review of PT/0/A/4200/04 and discussions with licensee personnel indicated that the guidance provided by the PT with regard to closing and sealing -the personnel / submarine hatch may have been inadequate to ensure TS compliance.
The maintenance technicians who completed WR 73967 on June 27 insisted that they had securely closed and dogged the hatch prior
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to attaching the wire tamper seal.
The hatch and tamper seal configuration apparently were such that the hatch's handwheel could be rotated a sufficient distance to undog the hatch without breaking the tamper seal.
The failure of PT/0/A/4200/04 to adequately control the closure and sealing of the containment personnel hatch is identified as a third-i example of apparent violation 50-370/87-21-02 against TS 6.8.1.
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