IR 05000369/1993003
| ML20035F262 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 04/01/1993 |
| From: | Cooper T, Lesser M, Miller W, Van Doorn P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20035F255 | List: |
| References | |
| 50-369-93-03, 50-369-93-3, 50-370-93-03, 50-370-93-3, NUDOCS 9304210093 | |
| Download: ML20035F262 (21) | |
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION ll
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101 MARIETTA STREET, N.W.
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f AT LANT A, GEORGI A 30323 i
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Report Nos. 50-369/93-03 and 50-370/93-03 Licensee:
Duke Power Company 422 South Church Street Charlotte, NC 28242-1007 Facility Name: McGuire Nuclear Station 1 and 2
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Docket Nos. 50-369 and 50-370 License Nos.
NPF-9 and NPF-17 Inspection Conducted:
February 14, 1993 - March 13, 1993
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Inspector:
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fo/- P. K. Van D oyn Date Signed 3/Ir/9.3 Inspector:
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Date Signed
[d T. A. Cooper Project Engineer:
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Date Signed (bh/
I Approved by:
,rrifM. S. Lesser, Section Chief Date Signed Division of Reactor Projects
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SUMMARY
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l Scope:
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This routine, resident inspection was conducted in the areas of plant I
operations, surveillance testing, maintenance observations, Licensee Event Report followup, engineered safety features testing, fire protection pr: yam, inspection and testing of modifications, and evaluation of licensee se:f j
assessment capability.
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Results:
In the areas inspected, one non-cited violation was identified involving two examples of inadequate engineered safety features testing (paragraph 6.).
Two unresolved items were identified. The first involved the failure to stroke time test a valve after backseating (paragraph 4.b.).
The second involved timaliness of evaluations for operations events (paragraph 9.d.).
Two weaknesses were noted. One involved inconsistent / incomplete operations logging (paragraph 2.e.).
The second involved reportability evaluations under the new corrective action program (paragraph 9.c.).
The inspectors also noted continuing misunderstanding by licensee personnel regarding implementation of the new corrective action program (paragraph 9.b.).
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l REPORT DETAILS 1.
Persons Contacted Licensee Employees D. Baxter, Support Operations Manager A. Beaver, Operations Manager
- J. Boyle, Work Control Superintendent
D. Bumgardner, Unit 1 Operations Manager
- B. Caldwell, Training Manager
- W. Cross, Compliance Security Specialist
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T. Curtis, System Engineering Manager
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J. Foster, Station Health Physicist
- E. Geddie, Station Manager
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l G. Gilbert, Safety Assurance Manager
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I P. Guill, Compliance Engineer
- B. Hamilton, Superintendent of Operations l
- F. Hayes, Human Resources Manager
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B. Hasty, Emergency Planner
- P. Herran, Engineering Manager
- L. Kunka, Compliance Engineer
- T. McNeekin, Site Vice President R. Michael, Station Chemist
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- T. Pederson, Safety Review Supervisor N. Pope, Instrument & Electrical Superintendent
- R. Sharpe, Regulatory Compliance Manager
- B. Travis, Component Engineering Manager r
- R. White, Mechanical Maintenance Superintendent
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Other licensee employees contacted included craftsmen, technicians, operators, mechanics, security force members, and office. personnel.
NRC Resident Inspectors
- P. Van Doorn, SRI
- T. Cooper, RI
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- Attended exit interview 2.
Plant Operations (71707)
a.
Observations 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 removal and restoration records were routinely reviewed.
Interviews were conducted with plant
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operations, maintenance, chemistry, health physics, and performance personnel.
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Activities within the control room were monitored during shifts and at shift changes. Actions and/or activities observed were
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conducted as prescribed in applicable station administrative directives. The complement of licensed personnel on each shift met or exceeded the minimum required by Technical Specifications (TS).
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The inspectors also reviewed problem investigation forms (PIPS) to determine whether the licensee was appropriately documenting
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problems and implementing corrective actions.
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.
The inspector conducted a special observation of the licensee protected area boundary fence.
Findings were discussed with licensee and NRC management.
While performing Unit 1 Auxiliary Building walk-thru inspection,
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the inspector checked to verify that the auxiliary shutdown panel j
was locked, by attempting to turn the handle of the door to the panel. When the handle turned freely, the inspector notified the control room SRO that the panel appeared to be unlocked. A non-licensed operator was dispatched. The operator verified that the panel was unlocked and relocked it.
The licensee has been unable to account for the panel being l
unlocked. The inspector verified that the key to this panel is l
controlled. The key is not usually checked out unless routine j
surveillance or preventative maintenance is being performed b.
Unit 1 Operations The unit began the period at 100 percent power and remained at or near that level until March 12, 1993 when the unit was shutdown for (
a refueling outage. This ended a unit record of 227 days on-line.
The outage is scheduled to last until June 10. On February 24, operators noted an increase in unidentified reactor coolant leakage to approximately 8 gallons per minute (gpm). The licensee discovered a packing leak at valve No. INV244. The valve was back-seated which reduced leakage back below the TS limit of 1 gpm (see paragraph 4.b.).
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Unit 2 Operations The unit began the period at 100 percent power. On February 22, 1993 the unit was manually tripped in anticipation of an automatic trip on low steam generator (SG) level.
Feedwater regulation valve
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2CF20 to 'C' SG had failed shut.
The licensee determined the cause of the valve failure to be a ruptured bellows in the positioner.
Later in the shutdown, the licensee noticed that main feedwater
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isolation valve 2CF30 could not be closed from the control room.
The licensee jumpered a pressure switch and the valve was able to i
be closed. The licensee determined that extensive rework would be required to fix this non-safety-related valve closure capability and decided to delay this corrective maintenance until a longer outage.
It should be noted that the automatic isolation capability of the valve remained operable.
All other plant equipment operated satisfactorily. The unit was returned on-line late on February 22 after replacement of the positioner bellows on all four feedwater regulation valves. The unit reduced power from approximately 85 percent to 15 percent on February 24 due to oscillation of 'D'
SG feedwater regulation valve 2CF17.
Power was returned to 100
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percent on February 25. Again valve 2CF17 began oscillating and load was decreased to 15 percent to effect repairs.
Power was
returned to 100 percent on February 27. On March 2, valve 2CF17 once again began oscillating in automatic on control channel 1.
Control was switched to Channel 2.
Circuitry was adjusted on March 3 for valve 2CF17.
On March 3, indicated upper thrust bearing temperature on reactor coolant pump (NCP) ' A' began increasing.
The licensee began a load decrease which was secured at 47 percent when a loose wire was found to have caused a false indication. The unit was returned to 100 percent power on March 4.
On March 9, the unit was manually tripped subsequent to feedwater regulation valve No. 2CF23 failing shut. Again, a positioner bellows was found ruptured. The licensee replaced the bellows on each of the four feedwater regulating valves with a diaphragm assembly that had been developed at the licensee's Catawba facility.
The unit was returned to 100 percent power on March 11 and remained at that level the remainder of the period.
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Special Reports i
During a review of the Control Room logs, the inspectors.oted that Channel Nos. 5 and 8 of the Unit 1 Loose Parts Detection System had been out of service since June 17, 1992. Channel 5 had a low noise level and Channel 8 had a high noise level. TS 3.3.3.10 requires a Special Report to be issued to the NRC if one or more of the Loose
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Parts Detection System channels is inoperable for more than 30 days. The report is required to outline the cause of the malfunction and the plans for restoring the inoperable channel to
operable status. This report is required to be submitted within
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the next 10 days following the 30 days that the detection channel is out of service.
The Special Report on the inoperable Loose Parts Detection System
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channels which was required to be submitted to the NRC on July 27,
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1992, was actually submitted on August 13, 1992. This report was identified by the licensee as being late. To prevent recurrence, the licensee has developed a tracking system for all Special and
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i License Event Reports. All events that require a written report to
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the NRC are listed on a Safety Review Status Board which is located l
in the Compliance Group work area.
This board is monitored daily
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l due date. This arrangement should assure that future reports are sent out on time.
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Logging Weakness
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Licensee requirements for operations logging are contained in Operations Management Procedure 2-4, Reactor Operator and Unit
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Supervisor Logbooks. This procedure requires Unit Supervisor Logbook entries to include, in part, the following:
Entries concerning equipment shared by both units which
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affect or could affect both units should be made in both Unit I and Unit 2 logbooks.
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Significant abnormalities which occur should be explained in
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greater detail than the Reactor Operator's Logbook. The chronological sequence of events and time of occurrence of significant abnormalities and related circumstances should be recorded in the log.
The status of out of normal station conditions and events
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l should be includea in the log in enough detail to provide a l
smooth transition from one shift to another.
Anytime the Shift Technical Advisor (STA) is notified of an
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abnormal situation, a log entry shall be made documenting the time he was notified and the time he arrived in the Control Room.
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l The inspector selected Unit Supervisors logs for February 16, 1993 through March 3, 1993 for review to determine if entries were thorough, met procedure requirements and were consistent. The following problems were noted:
i Notification and arrival times of the STA were not logged
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following a reactor trip which occurred during this period.
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The operations computer was logged out of service but no i
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entry was made upon restoration.
A shared control room ventilation train was logged out of
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service in only one log book.
A number of equipment problems were identified during the
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period.
Extensive maintenance and trouble shooting occurred for some of this equipment. Although initial entries were typically made noting the malfunction, followup entries were not always made and little detail was provided as to what l
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5 problems were found. This information could be valuable to succeeding shifts.
i A Unit 2 main feedwater regulation valve experienced
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oscillations over several hours on March 3,1993, requiring several adjustments to the control circuitry. No log entry was made regarding this problem.
The initiation time for one of several Unit 2 power decreases
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which occurred during the period was not logged.
The licensee indicated that the STA notification logging requirement was impractical and would probably be deleted. The STA is always available in close proximity to the control room. The licensee also indicated that supervision would begin reviewing the logs and improvements would be affected. The above problems were described at a meeting of Shift Supervisors.
This is considered a weakness in licensee logging practices.
No violations or deviations were identified.
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3.
Surveillance Testing (61726)
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Observation i
. Selected surveillance tests were analyzed and/or witnessed by the
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resident inspection staff to ascertain procedural and performance
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Selected tests were witnessed to ascertain that 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 acceptance criteria were met.
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l The selected test listed below was reviewed or witnessed in detail:
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PROCEDURE EQUIPMENT / TEST l
PT/0/A/4150/27A Moderator Temperature Coefficient Determination at End of Cycle
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PT/1/A/4350/02A Diesel Generator 1A Operability Test l
PT/1/A/4252/04 Auxiliary feedwater Valve Movement Test PT/2/A/4403/02A Nuclear Service Water Train A Valve Stroke Timing l
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PROCEDURE E0VIPMENT/ TEST PT/2/A/4250/04I Pre-Startup Turbine Testing l
PT/1/A/4250/04C Turbine Trip Test l
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Surveillance Adequacy Review
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'i Another licensee (South Texas Station) during a special review l
identified a number of inadequate surveillances. The inspector i
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discussed these problems with appropriate engineering personnel and independently reviewed licensee procedures to assure that these j
problems did not occur at the McGuire Station. The problems and I
the appropriate licensee surveillance procedures are listed below:
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Main steam isolation bypass valves were not being response.
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time tested (PT/l&2/4255/02).
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Manual reactor trip via the shunt trip device was not j
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independently tested (PT/0/A/4600/12).
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Feedwater isolation actuation and response time. testing did
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between safety injection and feedwater isolation because they l
did not test through the slave relays (IP/0/A/3010/06).
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Reactor Coolant Pump undervoltage and underfrequency
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L surveillance procedures did not require verification of bistable status monitoring lights operability
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In all cases the licensee's surveillance procedures were adequate.
However, another problem found at South Texas did lead to discovery l
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of an inadequate surveillance (see paragraph 6).
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Charging Pump Suction Line Check Valve Review i
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A possible leak path outside containment during a loss of coolant l
accident was discovered at the Beaver Valley Station. The event is i
described in Westinghouse Nuclear Safety Advisory Letter i
NSAL-92-012. The plant's configuration consisted of a check valve
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located downstream of the Volume Control Tank (VCT), two i
motor-operated isolation valves and a seal return line.
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plant was in the sump recir ulation mode after an accident and the
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Residual Heat Removal (RHR)- pumps were supplying flow to the l
charging pumps and the check valve leaked,. flow would be diverted through the seal water heat exchanger and could potentially lift a relief valve. The relief valve would relieve to the VCT. Once the VCT is full, it would overflow to the Liquid Hold-Up Tanks which are located outside located containment. This potentially results J
in a leakage of primary coolant outside of containment. This check t
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valve had previously been identified as not requiring testing.
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The inspector verified that the licensee had received Westinghouse's letter and reviewed the licensees evaluation of the problem.
The licensee has similar check valves (Nos.1 & 2NV143).
A manual isolation valve is maintained closed between the check valve and the seal return line preventing the specific Beaver Valley problem. However, a relief valve is located between the check valve and isolation valve which relieves to the VCT. The licensee has not been testing the check valve but plans to test the i
valve during an upcoming outage. Other check valve testing during outages did provide a flow path through this check valve back to the VCT.
No significant level increase had been noted in the VCT,
however, measurements were not recorded. The licensee was still
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evaluating a long term fix which may include raising the relief
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valve setpoint above the RHR pump shutoff head or deleting the
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relief valve.
Licensee actions appear to be appropriate.
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d.
Review of Nuclear Service Water Valves Personnel at the licensee's Catawba Station recently discovered
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that Nuclear Service Water (RN) pump discharge valves were subject to not opening under maximum postulated differential pressure (DP)
conditions. The inspector ceviewed the McGuire Station's
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evaluation of this problem. The discharge valves at McGuire are locked open during operations. This specific problem is not applicable at McGuire. The licensee also reviewed other valves in the RN System which could experience a similar problem. These included inlet and outlet valves for the component cooling (KC) and containment spray (NS) heat exchangers.
For the RN to KC valves, the inlet valve is subject to high DP upon startup of an idle train. However, this occurs regularly during operations and no problems have been noted.
In addition, scenarios involving
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sequencing power on to the Diesel Generators results in the inlet valves sequencing on before the pumps. The RN to NS valves were determined to have been tested under DP conditions greater than or equal to that expected during accident conditions.
No violations or deviations were identified.
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4.
Maintenance Observations (62703)
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Observation i
l Routine maintenance activities were reviewed and/or witnessed by the resident inspection staff to ascertain procedural and performance adequacy and conformance with the applicable TS.
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The selected activities witnessed were examined to ascertain that, i
where applicable, approved procedures were available and in use,
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that prerequisites were met, that equipment restoration was completed and maintenance results were adequate.
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The selected maintenance activities listed below were reviewed or
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witnessed in detail:
WORK ORDER ACTIVITY
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93011005 Turbine Driven Auxiliary Feedwater Pump Suction Pressure Calibration (1
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MCAPS 5380)
93011004 Turbine Driven Auxiliary Feedwater Pump Suction Pressure Calibration (1 MCAPS 5044)
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93010354 Oil Sample on 2A Auxiliary Feedwater Pump l
93002763 Diesel Generator Heat Exchanger Outlet Flow' Calibration l
92089344 Fabricate and Install Megasystems
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Mount 93012985 Periodic Testing / Preventive l
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Maintenance on SSPS Train A b.
Failure to Stroke Time Test a Backseated Valve On February 24, 1993, a packing leak was stopped on Valve No.
INV244 by backseating the valve. This is a containment isolation valve on a charging line. The licensee decided that backseating was not maintenance affecting stroke time except for the additional travel required by the valve. A calculation was performed to evaluate the effect of the additional travel on stroke time.
This indicated a stroke time of 8.72 seconds versus a requirement of 10 t
seconds. The licensee considered it impractical to isolate the charging line at power for stroke timing. The inspectors consider
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that backseating may affect the stroke timing of the valve and that
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the valve should have been stroke tested after backseating. The (
backseating of valves is not specifically addressed by ASME Section l
i XI Article IWV-3200.
The inspectors consider that backseating of
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testing may have been required.
- Pending further review of this issue by NRC, this is identified as Unresolved l'em 369,370/93-03-01:
Evaluation of Stroke Time
Testing fc"
. kseated Valves.
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5.
Licensee Event Report (LER) Followup (90712,92700)
The below listed LER was reviewed to determine if the information provided met NRC requirements. The determination included:
adequacy of description, verification of compliance with Technical Specifications and regulatory requirements, corrective action taken, existence of potential generic problems, reporting requirements satisfied, and the relative safety significance of the event. Additional implant reviews and discussion with plant personnel, as appropriate, also were conducted.
The following LER is closed:
369/92-02 TS Surveillance Requirement Missed Due to a Non-Conservative Calculation of Nuclear Flux Hot Channel Factor No violations or deviations were identified.
6.
Review of Inadequate Engineered Safety Features (ESF) Testing (61726)
a.
Inadequate Containment Spray Actuation Testing On February 16, 1993, site engineering personnel received notification via the licensee's Operating Experience Program (OEP)
of inadequacies in the testing of the Engineered Safety Features Actuation System (ESFAS) at the South Texas Station. As a result, the licensee discovered that a portion of the Containment Spray (NS) channels between the process instrumentation and the ESF actuation and logic circuitry was not being tested.
The ESFAS causes various ESF equipment to actuate to mitigate the consequences of postulated accidents. The ESFAS is comprised of the instrumentation and controls necessary to sense accident conditions and initiate the operation of necessary safety equipment.
During reactor operation, the basis for ESFAS acceptability is the successful completion of the overlapping tests performed on the initiating system and the ESFAS. Analog checks and tests verify the operability of the analog circuitry from the input of these circuits through, to, and including the logic input relays, except for the input relays associated with the NS function. The input relays associated with the NS function are tested during the solid state logic testing.
The Solid State Protection System (SSPS) receives inputs from the analog processing circuitry and processes these inputs through the logic circuitry to actuate ESF equipment. Some of the analog outputs also pass through the reactor trip circuitry. Analog testing for the NS function required that the input relay contacts to SSPS be opened to prevent an inadvertent NS actuation. Also, a contact in the reactor trip circuitry was required to be opened.
Upon completion of the required testing the contacts were returned
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to normal (closed). None of the operational tests verified that the associated contacts were closed and that there was circuit continuity.
Failure of the contacts to close would render the NS circuitry inoperable. The response time testing which is performed
during each outage utilizes these contacts and verifies circuit
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The ESFAS is normally deenergized to actuate except for the NS System. To prevent spurious NS actuation, the NS bistables are
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energized to actuate.
Because the NS circuitry is normally deenergized, there is no indication the system is inoperable such i
as is available for other ESF equipment via the bistable status monitoring panel.
Because of the " energize to actuate" design of
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the NS circuitry, a test circuit is provided to verify continuity
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of NS circuits between the process instrumentation and the ESF actuation and logic circuitry. The test circuit was not utilized i
by the licensee. The licensee initiated the continuity testing on j
February 17, and did not find a problem.
r Since the licensee did not find a continuity problem and outage testing had not identified problems, the licensee determined that a past operability problem did not exist. However, this was considered to be a missed surveillance and a violation of TS 4.3.2.1.
The licensee entered TS 4.0.3 which allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to
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complete a missed surveillance.
The licensee initiated changes to
appropriate procedures. The licensee also began to process an LER although this was begun approximately two weeks after the problem was identified (see weakness described in paragraph 9). This is identified as licensee identified issue and the licensee appears to i
be taking appropriate corrective action. Therefore, this violation
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will not be subject to enforcement action because the licensee's
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efforts in identifying and correcting the violation meet the j
criteria specified in Section VII.B. of the Enforcement Policy.
This is identified as Non-Cited Violation (NCV) 369,370/93-03-02:
Inadequate Surveillance Testing of Engineered Safety Features Actuation Circuitry.
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Inadequate Phase "B" Isolation Testing On March 2,1993, the inspector notified the licensee of a problem that existed at another station with the SSPS. The actuation logic test lead for Phase "S" actuation logic was landed on the Containment Spray Actuation Logic terminal (terminal TB501-5 vice TB501-6).
Because of this wiring discrepancy, when the monthly SSPS Actuation Logic Surveillance was conducted, the Phase "B"
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Containment Isolation Logic was not tested.
Instead, Containment Spray Actuation logic was tested twice. Since both actuation logics require 2-out-of-4 concurrence, the surveillance appeared to i
be satisfactory. The licensee checked SSPS terminal TB501-5 and TB501-6 on both channels on both units and found that they were miswired, resulting in the inability to perform the monthly surveillance on Phase "B" actuation logic.
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Technical Specification Table 4.3-2 requires that each train of the Phase "B" Isolation Automatic Actuation Logic and actuation relays l
be tested at least every 62 days on a staggered test basis. The miswired circuitry resulted in the missing of these surveillance
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since initial start-up. Upon discovery, the licensee entered TS I
3.0.3, but delayed the action requirements for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in accordance with TS 4.0.3 to currect the wiring discrepancies and perform the TS surveillance. The required tests were performed satisfactorily and the licensee exited TS 3.0.3.
Operability of Phase "B" isolation was not a concern since it has been evaluated as part of the 18 month testing for Engineered Safeguards.
The licensee responded rapidly to the information provided by the inspector; identifying the problem, developing a solution, implementing the wiring changes, and performing the surveillance.
Failing to perform the TS required surveillance is another example of NCV 369,370/93-03-02:
Inadequate Testing of Engineered Safety
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Features Actuation Circuitry.
The NRC identified violation is not being cited because criteria specified in Section VII.B of the NRC Enforcement Policy were satisfied.
One non-cited violation was identified.
7.
Fire Protection Program (64704)
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The inspector reviewed the implementation of portions of the licensee's
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a.
Fire Brigade Organization Previously, two fire brigade organizations were provided. The primary brigade was composed of operations personnel. The I
secondary fire brigade was composed of personnel from other departments. These two organizations have been consolidated into a single fire brigade organization. As of March 1, 1993, there were a total of 180 trained and qualified fire brigade members. An average of 32 fire brigade members were assigned to each shift.
The new fire brigade organization is composed of personnel from the operations, instrumentation and electrical, maintenance, radiation
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protection and chemistry departments.
Normally, the Assistant Shift-Supervisor is the fire brigade team leader. Since most of the operations shift personnel are qualified fire brigade members, there is sufficient operational employees available to meet the TS requirements for providing a minimum of five operators for the brigade.
The inspector reviewed the fire brigade drill data for the drills conducted on February 16 and 18, 1993. A total of 34 brigade members responded to the February 16 drill and 25 responded to the February 18 drill. The licensee stated that this response was typical. To control fire brigade activities and assign fire fighting duties to the responding personnel, the licensee utilizes i
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a fire brigade command post. This eliminates confusion during fire (
drills and fire emergency events.
Fire brigade drills are conducted at frequent intervals, with the l
l interval between each shift limited to not more than 90 days, i
Previously, Station Directive 2.11.1 permitted a plus or minus 21
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l day grace period between quarterly drills. This did not meet the
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NRC guidelines. The Directive has been revised to eliminate the
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grace period. Thus, the Directive now meets the NRC guidelines.
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The inspector inspected the two fire brigade equipment storage l
areas in the Turbine Building and found the fire brigade turnout l
gear and equipment to be properly stored and well maintained.
b.
Fire Damage Control Equipment i
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The inspector performed an inspection of the electrical equipment required to implement Procedure IP/0/A/3090/23, Fire Damage Control Procedure. The electrical cables required by the procedure were
properly identified and stored on steel cable reels in Warehouse 6, l
l which is outside the protected area. This building is of pre-cast
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concrete construction and provided with automatic sprinkler
protection. During a previous inspection (NRC Inspection Report i
l No. 50-369/370/92-01), these cables were found stored in an outdoor i
storage area and not protected from the weather elements. Also,
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some of the cable reels were of wood construction and had begun to deteriorate. The present storage arrangement is an improvement over the previous storage and provides adequate protection for the cables.
The remaining equipment required by this procedure is satisfactorily stored in a wooden storage container in Warehouse
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This warehouse is located within the protected area. This building is of all-metal construction and provided with automatic sprinkler protection.
Procedure IP/0/A/3090/23, Enclosure 11.83, has been revised to l
include a list of the fire damage control equipment and the quantity of each item required.
This will permit the licensee to verify that the required equipment and correct quantity is l
maintained on site.
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Fire Protection Systems A walkdown inspection was performed by the inspector of the following fire protection systems:
Valve / System No.
Description of Area Protected Halon System Unit 1 Diesel Generator Rooms IA and IB
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Valve / System No.
Description of Area Protected Halon System Unit 2 Diesel Generator Rooms 2A and 2B Halon System Unit 1 Turbine Driven Auxiliary Feedwater Pump Room l
Sprinkler System 1RF951 Component Cooling Pumps 2A1, 2A2, 2B1 and 2B2
j Sprinkler System 1RF927 Charging Pump IB
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Sprinkler System IRF929 Charging Pump 2B
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Sprinkler System IRF940 Nuclear Service Water Pumps lA, 2A,
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These systems were found to be in service and appeared to be f
satisfactorily maintained.
j No violations or deviations were identified.
8.
Inspection and Testing of Modifications - Unit 1 (37828)
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The inspectors reviewed Nuclear Station Modification (NSM) design documents for the following modifications which are to be accomplished during the Unit I refueling outage that started on March 12, 1993:
Modification No.
Description l
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MG 12131 Add Vents and Drains to Component Cooling Water Heat Exchanges MG 12266 Revise Load Centers for Breaker Coordination MG 12301 Add Redundant Annulus Pressure Instrumentation for Annulus Ventilation System MG 12302 Re-orient Main Steam Safety Valves for Loop A MG 12398 Add Check Valves Downstream of Containment Spray Pumps The documentation reviewed for each modification included:
Design Engineering Scope Document
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10 CFR 50.59 Evaluation
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Engineering Calculation
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4 Modification Summary and Project Description i
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Changes to Equipment or Components
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Modification Test Plan
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Dose Estimates
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ALARA Worksheet
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Fire Protection Review
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These documents were thorough, well prepared and described in detail the
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work to be accomplished by the modification. However, during the review the inspectors noted that some of the file data was not stored in the correct file folder. The McGuire Nuclear Station Modification Manual, Revision 1 (September 21,1992), Section 6.5.11 requires all of the original modification documents, other than those specified in the Nuclear Station Modification File (limited edition drawings, as-built drawings, vendor manuals, vendor drawing, etc.) to be maintained in separate files under the supervision of Document Control. These documents are to be divided into the following five main folders:
I Folder 1.0 Main Required Components (Scope documents
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and 10 CFR 50.59 evaluation)
Folder 2.0 Document Transfer Information (Document
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Control information)
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Folder 3.0 Group Specific Information
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3.1 Civil
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3.2 Electrical 3.3 Mechanical Folder 4.0 Variation Notice Information
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Folder 5.0 All Other NSM Related Information (FSAR and i
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TS changes and project schedule
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information)
Document Control personnel estimated that approximately 2/3 of the NSM documents under their control have not been refiled to meet these requirements. These requirements were implemented in 1992 following the licensee's reorganization which moved the Design Engineering group onto the site. Most of the documents generated since September 1992 appear to be properly filed, but a large number of the documents issued prior to September 1992 are not properly filed. The licensee is reviewing the situation and is to establish goals to bring the storage of these files into compliance with the Modification Manual requirements. The dates in which the files will be brought up-to-date will be determined by early April 1993 and will be discussed with the Resident Inspectors.
It appears that all of the required NSM documents are either stored in Document Control or can be located by Document Control. Therefore, this discrepancy is not considered a significant regulatory issue.
Furthermore, the licensee has committed to bring the storage of the NSM
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documents up to the requirements of the Modification Manual. This will be verified during subsequent NRC inspections.
l No violations or deviations were identified.
9.
Evaluation of Licensee Self-Assessment Capability (40500)
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Observation of Nuclear Safety Review Board
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The inspector observed a Nuclear Safety Review Board (NSRB) meeting
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on February 24 and 25, 1993. Documentation of technical
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information presented to the Board was reviewed in order to assess whether the independent review and audit requirements of TS 6.5.2 l
were being met
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l The subjectu covered at the NSRB meeting included on overview of compliance issues such as operability evaluations, LERs, PIRs, violations, and lower tier corrective action program findings; top management issues; steam generator status; secondary side reliability; backlog status; configuration control issues; reactor
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coolant temperature spiking; shutdown risk; nuclear service water air entrainment update; valve testing update; and previous open t
items. The Board also conducted interface meetings with plant I
personnel. The subjects were timely and appropriate considering recent operational history and current problems. The Board was thoroughly briefed by plant personnel in multiple areas, in order to provide for an independent review. The inspector noted that members of the board were receiving adequate technical inputs, were asking technically sound questions, and making valid observations
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on issues.
Feedback was offered to plant management personnel.
l Whenever an issue could not be resolved at the meeting, action items were being issues. The Board's conclusions were generally i
l consistent with other site evaluations. The Board recommended that:
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The process for changing documents such as the Final Safety Analysis Report be formalized; that the site assure that programs which are used to clear corrective actions items, such as the station modification program, are closely l
monitored to assure completion of actions; and that
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management consider more structured problem solving within
the secondary reliability task force. A number of
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observations were noted. One observation involved longstanding equipment tagouts._ This was a repeat observation but was not strongly highlighted as such by the i
Board.
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b.
Problem Investigation Process During the February 23, 1993, startup of Unit 2 following the i
February 22, 1993, reactor trip, the power ascension was halted at
41 percent power, due to control problems with the feedwater
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regulating valve 2CF17 to the 'C' steam generator.
Instrument and Electrical (I&E) personnel adjusted the gain on the controller and returned the valve to service.
On February 24, 1993, with tha.< nit at 84 percer.t power, valve 2CF17 was again observed to be improperly functir.iing.
Power was reduced to approximately 15 percent power, tn allow transfer to the bypass regulating valves while repairs were made to the main feedwater regulating valve.
Power ascension was then resumed.
After power reached 100 percent on February 25,1993, valve 2CF17 was noted again to be functioning erratically.
Power was again reduced to approximately 15 percent to allow repairs.
Following adjustments to the controller, power was returned to 100 percent.
The inspector requested a copy of the Problem Investigation Process report (PIP) on the problem following the power decrease on February 24, 1993.
The Safety Review Group (SRG) informed the inspector that a PIP had not been written, but that they would discuss the matter with Operations and I&E.
Following the second power reduction, the inspector repeated the query to see the PIP.
The SRG informed the inspector that a PIP still had not been written. On March 2, 1993, the SRG informed the inspector that since both Operations and IAE were reluctant to issue a PIP on the problem with valve 2CF17, the SRG was going to e ite one.
On March 3,1993, while completing the Reactor Coolant (NC) Pump Data Sheet, the Reactor Operator noted that the Unit 2 'A'
NC Pump Upper Thrust Bearing Temperature was approximately 43' fahrenheit higher than the M her NC Pumps and was cortinuing to increase.
The operators entered procedure AP/2/A/5500/08, Malfunction of NC Pump.
Power was reduced to 47 percent before the indication was
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determined to be erroneous. The inspector asked the Operations Shift Supervisor (OSS) if a PIP had been written. The OSS informed the inspector that he had not planned to, but that one shuld be written by I&E. The OSS called I&E and was informed that they did not plan to write one. The OSS then wrote one.
i License Precedure NSD 208, Problem Investigation Process, Appendix E, includes a list of examples requiring the initiation of a PIP. Among these are equipment / system concerns and unscheduled power reductions.
The three events described above are examples of
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events requiring the initiation of a PIP. According to the SRG, these types of events shoLld have PIPS written for investigation.
NSD 208, Step 208.4, Problem Identification, states that a PIP will be initiated for any situation, condition, or occurrence or event that is abnormal, unex: 'cted or contrary to stated expectations with the exception of those problems entered into one of several formal programs, including Work Requests.
This exception appears to have been interpreted to prevent PIP generation in several instances. This interpretation of the exception is disputed by the
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SRG, which demonstrates the lack of clarity in the procedure or
when a PIP should be initiated.
This new corrective action program is an improvement over the previous program. The misunderstanding by licensee personnel in the implementation of this program is considered normal. The licensee is evaluating this area to determine if procedure changes and training are required. The inspectors will continue to monitor the licensee's imp % mentation of this program.
c.
Corrective Action Program Weakness Regarding Reportability Evaluation r
The licer.see's recently implemented corrective action program requires problems to be categorized as Lesser Significant Events
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(LSEs) or More Significant Events (MSEs). MSEs get an automatic review for reportability to NRC as required by 10 CFR 50.73.
LSEs do not get reviewed for reportability. The event described in paragraph 6.a. was initially classified as an LSE by the engineer since past operability was not considered a problem. The event, j
however, was a missed TS surveillance which is reportable. On
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March 2, 1993, the inspector questioned whether an LER was in progress for the event. The licensee discovered that the event was classified as an LSE and recognized the apparent weakness in the new program in that some issues categorized as LSEs could go unreported.
The licensee immediately upgraded the event to an MSE and categorized it as reportable within the 10 CFR 50.73 time limitation. The licensee also changed the PIP computer program to
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require missed surveillance to be categorized as MSE:;. The
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licensee indicated that a more generic long term fix would be
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developed. The generic corrective action will be reviewed during a
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future inspection.
d.
Operating Experience Program Review
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The licensee's OEP is described in Nuclear System Directive (NS0)
204. This NSD requires evaluation and develcpment of corrective actions within 90 days of distribution for " normal attention items" such as event reports from other stations.
In the case of the event described in paragraph 5.a, the event dest-iption was distributed by the OEP staff on November 9, 1992, to corporate technical staff. Tha event was not forwarded to site staff until late on February 16, 1993. Site staff implemented corrective
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Further review is necessary to determine whether this is an isolated event.
Thi.s is identified as Unresolved Item 369,370/93-03-03:
Evaluation of OEP Timeliness.
The inspectors requested information from the licensee which indicated the licensee's corrective action or response tn NRC Information Notices. This information is required by N1?
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to be provided in the Safety Assurance Section for review by the NRC inspectors. However, this information was not available on site.
This problem was previously identified by Duke's Quality Verification Audit No. NG-92-09 (GO) of October 14, 1992, but corrective action had not yet been impleaented.
Presently, the corrective action on this audit finding is under review.
It appears that the requirement to maintain information at the site on NRC Information Notices may be deleted. This area will be inspected during the followup of the Unresolved Item described above.
e.
Quality Verification Audit Review The inspector reviewed licensee audit No. NG-93-03 (MC) covering implementation of the Quality Assurance Program (QAP). This review was conducted to determine whether the licensee is actively assessing implementation of the QAP since a major reorganization implemented in late 1991. The licensee determined that the QAP was being implemented without adverse effect.
However, weaknesses were noted in that 40 directives have not been issued and no formal training had yet been conducted regarding the Nuclear Policy Manual and the Engineering Document Manual.
Findings were issued to assure followup. The audit appropriately highlighted important weaknesses.
Further inspection will be conducted regarding licensee corrective actions for the findings.
No violations or deviations were identified.
10.
Exit Interview (30703)
The inspection scope and findings identified below were summarized on March 16, 1993, with those persons indicated in paragraph I above. The following issues were discussed in detail:
Unlocked Auxiliary Shutdown Panel (paragraph 2.a.).
j Operations Logging Weaknesses (paragraph 2.e.).
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Unresolved Item 369,370/93-03-01:
Evaluation of Stroke Time Testing for Backseated Valves (paragraph 4.b.).
Non-Cited Violation 369,3/0/93-03-02:
Inadequate Testing of Engineered Safety Features Actuation Circuitry (paragraph 6.).
Documentation Filing Discrepancies (paragraph 8.).
Problems Associated With Implementation of the Licensee's New Corrective Action Program (paragraphs 9.b. and c.).
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Unresolved Item 369,370/93-03-03:
Evaluation of OEP Timeliness (paragraph 9.d.).
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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