ML20035F353
| ML20035F353 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 04/13/1993 |
| From: | Johnson W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20035F345 | List: |
| References | |
| 50-482-93-03, 50-482-93-3, NUDOCS 9304210185 | |
| Download: ML20035F353 (30) | |
See also: IR 05000482/1993003
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report:
50-482/93-03
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Operating License No.:
Docket:
50-482
Licensee: Wolf Creek Nuclear Operating Corporation
P.O. Box 411
Burlington, Kansas 66839
Facility Name: Wolf Creek Generating Station
Inspection At: Coffey County, Burlington, Kansas
Inspection Conducted:
February 13 through March 27, 1993
Inspectors:
G. A. Pick, Senior Resident Inspector
L. E. Myers, Resident Inspector
P. A. Goldberg, Reactor Engineer
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R. V. Azua, Resident Inspector, Fort Calhoun Station
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Approved:
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Division ov,$hiEf, Proj'ect Section A
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Reactor Projects
Inspection Summary
Areas Inspected:
Routine, unannounced inspection including plant status,
operational safety verification, maintenance observations, surveillance
observations, reliable decay heat removal during outages, refueling
activities, followup on corrective actions for violations, other followup, and
in-office review of licensee event reports (LER).
Results:
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The inspectors identified two examples of a violation of Technical
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Specification 6.8.1.a concerning inadequate control and coordination
during clearance order implementation.
A radioactive gas release
occurred inside containment because of miscommunication during shift
turnover, and personnel placed clearances in the wrong order that
resulted in additional draining of the reactor coolant system below
midloop (Sections 2.6 and 2.13).
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Two noncited violations were identified. After discovering Technical
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Specification 3.9.4 was violated, the licensee quickly implemented
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effective actions to prevent recurrence (Section 2.8).
The licensee
determined that a personnel oversight resulted in a failure to perform an
as-found local leak rate test (Section 2.11).
A licensee investigation team determined the root cause and recommended
appropriate corrective actions in response to a containment purge
isolation. The investigation was comprehensive and demonstrated an
increased awareness by licensee management of the need to respond to
events (Section 2.6).
The licensee conducted a thorough but untimely evaluation of a reactor
protection system response time testing concern.
After the inspectors
expressed concern regarding timeliness of work group evaluations, the
licensee initiated a quality assurance surveillance (Section 2.2).
Qualified quality assurance personnel provided performance based 24-hour
coverage of the plant shutdown, and security conservatively increased the
sensitivity of metal detectors beyond that required in the security plan
(Sections 2.3 and 2.7).
The licensee implemented a good response to pressurizer temperature
transients (Section 2.4).
During a reactor coolant system drain down,
the licensee continued to drain with a level discrepancy, but the
licensee used the most negative indication as the true level
(Section 2.5).
The inspectors determined that, overall, the licensee had a good safety
program and an excellent program for controlling scaffolding
(Section 2.10).
The licensee initiated a performance improvement request (PIR) to
document that measuring and test equipment out-of-calibration evaluations
were significantly backlogged. After the inspectors expressed concern
about operability of equipment needed in Modes 5 and 6, the licensee
promptly reviewed all outstanding evaluations, determining that no
operability problems existed.
The inspectors considered the licensee
f ailure to evaluate equipment operability 4 months earlier, when quality
assurance personnel identified the deficiency, to be a weakness
(Section 3.1).
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The inspectors determined that the licensee established a well-planned,
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conservative outage schedule that ensured reliable decay heat removal and
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included availability of both onsite and offsite power supplies related
to the operable decay heat removal train (Section 5).
The inspectors determined that licensee programs assured compliance with
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refueling related Technical Specifications.
The licensee established
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strong controls for loose objects around the spent fuel pool. The
licensee thoroughly evaluated a method to perform vacuum venting of the
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reactor coolant system. The venting was determined to be necessary to
help minimize transgranular stress corrosion cracking of canopy seal
welds on spare reactor vessel head penetrations. The licensee identified
a failed fuel rod in an F-type assembly (Section 6).
Summary of Inspection Findings:
Violation 482/9301-01 was opened (Sections 2.6 and 2.13).
Violations 482/9126-02, 482/91202-01, 482/9208-01, 482/9208-02, and
482/9212-02 were closed (Section 7).
Inspection Followup Items 482/9202-01 and 482/9301-02 and a 10 CFR
Part 21 report were closed (Section 8).
Licensee Event Reports 482/91-013, 482/91-018, 482/92-001, 482/92-004,
482/92-011, and 482/92-012 were closed (Section 9).
Attachments:
Attachment 1 - Persons Contacted and Exit Meeting
Attachment 2 - Documents Reviewed
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DETAILS
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1 PLANT STATUS (71707)
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At the beginning of the inspection period, the plant operated at 100 percent
power. On March 4, 1993, the licensee began a controlled shutdown in order to
begin Refuel VI.
At the end of the inspection period, the reactor was
completely defueled.
2 OPERATIONAL SAFETY VERIFICATION
(71707)
The objectives of this inspection were to ensure that the facility was being
operated safely and in conformance with license and regulatory requirements,
and that the licensee's management control systems were effectively
discharging the licensee's responsibilities for safe operation.
The methods used to perform this inspection included direct observation of
activities and equipment, observation of control room operations, tours of the
facility, interviews and discussions with licensee personnel, independent
verification of safety system status and Technical Specifications limiting
conditions f ar operation, verification of corrective actions, and review of
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facility records.
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2.1
Loss of Offsite Notification Ability
On February 16, 1993, the licensee lost offsite power to the surrounding area
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and the emergency operations facility for a 3-hour period.
The following
afternoon, the licensee made a 1-hour 10 CFR Section E0.72 notification after
determining that six emergency plan sirens had lost power the previous day.
The licensee considered the loss of the sirens a major loss of emergency
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response capability.
The inspectors reviewed the program established for offsite agencies to notify
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the facility when emergency response sirens become inoperable.
The licensee
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had signed memorandums of agreement in 1988 specifying the notification
requirements; however, because the system had not been exercised, offsite
personnel failed to quickly recall their responsibilities.
Because of this event, the licensee conducted meetings with county personnel
to develop a plan to prevent recurrence.
The licensee signed new memorandums
of agreement and established a requirement in Procedure EPP 02-1.8, " Testing
and Maintenance of Alert and Notification System Status," Revision 7, to
remind agencies annually of their notification responsibilities for loss of
emergency response capabilities. The licensee revised Procedure ADM 01-033,
" Instructions for Evaluating, Reporting, and Documenting Potentially
Reportable Events," Revision 28, to specify that a loss of three or more
sirens for greater than I hour constitutes a major loss of the offsite
notification system and should be reported.
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2.2 Reactor Protection System Response Time Testing
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On February 28, 1993, the licensee informed the inspectors that the Technical
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Specifications surveillance tests for reactor protection system response times
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did not account for all delays assumed in the safety analysis. The licensee
reviewed this condition in response to Industry Technical Information Program
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Item 01985, " Technical Bulletin 92-03: Westinghouse Trip Protection." The
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vendor issued the letter to all plants with reactor coolant pump undervoltage
trip protection to address confusion related to response-time testing.
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vendor had determined that some plants did not include the time delays related
to the effects of back electromotive force and associated with opening of the
control rod drive mechanism gripper fingers. The licensee determined that.
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when testing the reactor coolant pump undervoltage trip response time, they
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failed to account for the back electromotive force and the gripper finger
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release time delays. Additionally, the licensee determined that they did not
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include the gripper finger release time delays in other response time tests.
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However, the licensee included the gripper finger release time during rod drop
testing, as specified in the Technical Specifications.
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On March 4, 1993, the licensee initiated PIR AN 93-0141 to ensure that the
issue would be resolved and initiated Work Request 01131-93 to ensure
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operability would be evaluated. The licensee made a 10 CFR Section 50.72
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report based on potentially being outside their design bases. This report was
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retracted on March 18, 1993. The operability evaluation for Work
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Request 01131-93 determined by a calculation that the back electromotive force
effects approximated 200 milliseconds (ms) and by review of past rod drop
tests that the gripper release time was 60 ms.
Adding 260 ms to the longest
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recorded time delay from surveillance tests (1.215 seconds) resulted in a time
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delay of 1.475 seconds, less than the acceptance criteria of 1.5 seconds.
The licensee initiated voluntary LER 482/93-001 and determined that other
reactor protection system instrumen't response times were not exceeded.
While
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reviewing the circumstances surrounding this deficiency, the licensee
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determined that:
(1) currently existing programs for assuring that they
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adhered to the safety analysis were adequate, (2) the root cause was an
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inadequate vendor definition of response time testing, and (3) sample reviews
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of other analyses would not be worthwhile. The licensee implemented or will
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implement the following additional actions:
(1) documenting the processes
used by nuclear analysis when they assumed responsibility of each safety
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analysis from the vendor, (2) determining the actions needed to resolve
problems identified in the safety analysis, and (3) addressing this generic
issue with the vendor owner's group.
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The inspectors determined that the Industry Technical Information Program
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coordinator received Technical Bulletin 92-03 on June 4,1992. The Industry
Technical Information Program coordinator issued Industry Technical
Information Program Item 01985 on July 6,1992, to design engineering after
discussing the potential that back electromotive force was not included in
response time testing. On August 7, 1992, design engineering requested an
extension until February 5,1993, based on the results of the NRC Electrical
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Distribution Safety Functional Inspection conclusions on undervoltage relay
response time testing. On February 12, 1993, a preliminary evaluation-
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concluded that gripper release and back electromotive force time delays were
not included in response time testing.
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Based upon the vendor numbers for back electromotive force and gripper release
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response times, the Techn'ical Specifications required response time would be
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exceeded. The inspectors expressed concern because of the delay in evaluating
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Industry Technical Information Program Item 01985.
In response to the
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inspectors' concern, the Vice President, Nuclear Assurance initiated a quality
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assurance surveillance to evaluate the effectiveness of the initial
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evaluations of Industry Technical Information Program items upon receipt by
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the work groups.
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2.3 Ouality Assurance Surveillance Activities
During the plant shutdown from Modes 1 to 5, two quality assurance auditors,
who held or had held operator licenses at Wolf Creek, provided 24-hour
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coverage for approximately 3 days. The auditors documented their observations
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in Surveillance S-2003, " Plant Shutdown, Mode 1 to Mode 5."
The auditors
noted:
(1) outstanding control room communications among operations personnel
and among the operators and other work groups, (2) that system engineers
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actively assisted the shift supervisor in resolving problems, and (3) that
operators performed the plant shutdown in a well-controlled manner with
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heightened awareness to seismic nnitor alarms. During the surveillance, the -
auditors issued PIR OP 93-0146 that documented a failure to log into the-
control room log an instrument air bypass valve found out of position and a
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lifting relief valve. The manager of operations issued a memorandum
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specifying the need to document all problems and challenges to systems.
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Quality assurance had not accepted the response at the end of the inspection
period.
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2.4 Pressurizer
On March 8,1993, while cooling down the plant in preparation for Refuel VI,
the licensee exceeded the pressurizer cooldown rate of 200oF/ hour specified in
Technical Specification 3.4.9.2.
Approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later, the licensee
exceeded the pressurizer heatup rate of 100oF/ hour specified in Technical Specification 3.4.9.2.
This phenomenon occurred on two occasions in 1992
during plant cooldowns (refer to NRC Inspection Report 50-482/92-02,
Section 5.14). The licensee evaluated the effects on the pressurizer of
exceeding these limits. The licensee reviewed pressurizer water temperature,
pressurizer steam space temperature, charging flows, letdown flows, and
pressurizer surge line temperatures to perform the evaluations.
The licensee determined that the excessive cooldown lasted for 8 minutes with
a temperature change of 242oF because reactor coolant system water surged into
the pressurizer.
The insurge occurred because of the charging / letdown
mismatch, and the pressurizer spray flow rate was insufficient to force flow
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from the pressurizer. After going solid in the pressurizer, the licensee
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determined that an excessive heatup rate lasted for 40 minutes with a
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temperature change of 130of as the hotter liquid volume in the upper part of
the pressurizer displaced the cooler liquid volume in the lower part of the
pressurizer.
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The inspectors determined that the licensee contacted the vendor regarding the
consequences of the pressurizer temperature transients. The vendor concurred
with the licensee's evaluation that the transients did not significantly
affect the integrity of the pressurizer walls or bottom nozzle. The
inspectors determined that a vendor owner's group insurge/outsurge evaluation
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program had an estimated completion date of December 1994.
Since the
cooldown/heatup transients experienced were less severe and occurred less
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frequently than transients in design analyses, the licensee concluded that the
accumulated fatigue usage factor for the pressurizer was within design.
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Consequently, the licensee determined that the pressurizer could be used as
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The inspectors determined that the licensee will implement changes to their
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operating procedures prior to drawing a bubble in the pressurizer to minimize
insurges and outsurges. The licensee will create / collapse the bubble at a
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higher temperature so the spray flow can be increased to ensure flow goes from
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the pressurizer to the surge line.
In the future the same methodology will be
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used to 90 solid. By operating the pressurizer in this manner, the delta
temperatures between the reactor coolant system and the pressurizer are
decreased minimizing temperature transients.
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2.5 Level Instrument Deviations
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On March 9,1993, the licensee initiated a reactor coolant system drain down
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to 18 inches below the reactor vessel flange so that the vessel head could be
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lifted, as specified in Procedure GEN 00-007, "RCS Drain Down," Revision 12.
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When draining the reactor coolant system, the licensee uses two independent
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level instruments and a tygon hose. Operations personnel verified that no
kinks, low points, or loop seals existed in the tygon hose. The individual
stationed inside the containment building to monitor the tygon hose level
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periodically communicated the level readings to the control room. Prior to
beginning the drain down, instrumentation and control technicians calibrated
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the midloop level instruments in accordance with Procedure STN IC-286, "RCS
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Midloop Level Instrumentation Calibration," Revision 0.
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The licensee established a controlled drain down process, but several delays
occurred.
For example, since the licensee added nitrogen to the reactor
coolant system to help remove fission product gases, personnel changed
nitrogen bottles when the bottle pressure decreased. Approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
into the drain down, operators stopped draining the reactor coolant system
because a 30-inch level discrepancy existed between the tygon hose and the
level transmitters. After investigating, the licensee removed a loop seal
that had developed in the tygon hose. Also, the operators stopped draining to
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perform a shift turnover.
Later, after resuming the drain down, operators
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determined that a 16-inch difference existed between the level transmitters
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and the tygon hose.
No problems were identified in the tygon hose. Draining
was continued until the water level was 18 inches below the flange, as
determined by the lowest indicating instrument.
After reducing the water level to 18 inches below the flange, the licensee
began troubleshooting the 16-inch level discrepancy.
During the
troubleshooting, the levels diverged to a maximum of approximately 30 inches.
The operators altered the charging and letdown flows to ensure that the lowest
indicated level remained higher than 3 feet below the flange to prevent
entering reduced inventory conditions.
The next day after instrumentation and
control technicians drained water from the reference leg for the level
transmitters under Work Request 01386-93, the level difference between the
transmitters and the tygon tube agreed within 1/2 inch. The licensee
determined that on March 9,1993, personnel had opened the midloop level
instrument root valves with the pressurizer level above the instrument taps,
as permitted by Procedure GEN 00-007, which prevented the reference leg from
draining. Subsequently, after the pressurizer water level decreased below the
instrument taps, the licensee drained the reference legs. The licensee
determined that the level indications diverged during the drain down because
water droplets that had adhered to the instrument tube walls slowly collected
in the reference leg tubing.
The change in relative pressures caused the
indicated level deficiency. The licensee changed Procedure Gen 00-007 to
insure the reference leg isolation valves will not be opened until the
pressurizer water level drains below the pressurizei instrument taps.
2.6 Containment Purge Isolation
On March 10, 1993, a containment purge isolation and control room ventilation
isolation occurred when gaseous activity exceeded the activation setpoint of
1.00 E-3 uCi/ml on Radiation Monitor GT RE-022, located in the containment
purge ventilation duct. As reported under 10 CFR Section 50.72, the licensee
evacuated 77 people from the containment building. The licensee determined
the root cause to be the release of gases from the pressurizer relief tank
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through the excess letdown heat exchanger drain line.
On March 11, 1993,
approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> later, Radiation Monitor GT RE-022 went into alert.
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response to the alarm, the operators manually isolated the containment purge
system before an automatic isolation occurred.
The 'nspectors reviewed
computer printouts and interviewed personnel and determined that an engineered
safety features isolation would not have occurred.
In response to these
events, the Vice President, Plant Operations established an investigation team
in accordance with Procedure ADM 01-116, " Incident Investigation," Revision 4,
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to address:
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The cause of the containment purge isolation,
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Operator actions,
Radiological consequences, and
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Lessons learned including corrective actions.
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The investigation team reviewed other ongoing activities determining that the
sequence of events that caused the gas release involved opening Valve BG V221,
excess letdown heat exchanger tube side combined drain valve.
The licensee
determined that the 9 psi gas pressure in the pressurizer relief tank applied
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against the seats of Target Rock Valves BG HV8157A and -B, excess letdown heat
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exchanger outlet to pressurizer relief tank isolations, created a flow path
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into the containment building. The investigation team identified several root
causes and specified corrective actions. The root causes included:
(1) the
design misapplication of Valves BB HV8157A and -B, (2) operations personnel
were unaware of the unidirectional properties of the solenoid vales, and
(3) the lack of timely distribution of solenoid operated valve
problem /information. Because of these deficiencies, operations personnel
inappropriately used the solenoid valves as clearance order boundary valves.
The investigation team determined h contributing cause was the implementing
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order of work activities within the outage window, which included work on the
reactor coolant drain tank.
The licensee measured the exposure from the thermoluminescent dosimeters of.
the last two individuals who left containment. The licensee calculated the
highest potential skin and whole body exposures to be 15 and 12 mrem,
respectively. From review of radiation monitor data, the licensee determined
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the maximum gas activity to be 1.45 E-3 uCi/ml and leveled at 4.33 E-4 uCi/ml.
The licensee determined that for future events the actuation setpoint will be
1.0 E-2 uCi/ml to be consistent with the Offsite Dose Calculation Manual for
Shutdown Conditions. The licensee determined that the containment evacuation
generally went well.
Following the containment purge and control room ventilation isolations, the
manager of operations directed that Clearance Order 93-0435-BG be changed to
restore the reactor coolant drain tank to allow depressurizing and draining
the pressurizer relief tank in accordance with Procedure SYS BB-202,
" Pressurizer Relief Tank Operation," Revision 16, to remove the gases.
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day shift personnel did not develop the changes to Clearance Order 93-0435-BG,
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but the night shift personnel did develop the necessary changes in accordance
with the turnover information provided. However, during the turnover to night
shift personnel, day shift personnel did not adequately stress the need to
keep Valve BG V221 closed and not place the associated five clearance order
tags. Consequently, personnel inadvertently took the original set of
clearance order tags and the change clearance order tags to the field and
reopened Valve BG V221 without the cognizance of the shift
supervisor / supervising operator.
Approximately 10 minutes after personnel opened Valve BG V221, Radiation
Monitor GT RE-022 alarmed at the alert setpoint. The failure of operations
personnel to perform an adequate turnover indicated a weakness in control and
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coordination of clearance orders that could have resulted in an unnecessary
engineered safety features actuation. Also, the inspectors determined that
the licensee had no formalized method to control tags that are not placed as
intended.
Procedure ADM 02-100, " Clearance Order Procedure," Revision 27,
Step 7.1.3.4, specified that, "After the clearance and tags have been prepared
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and approved, the shift supervisor / supervising operator shall review the
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tagging arrangement and reverify that the clearance will not adversely affect
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the plant." This is the first example of a violation of Technical
Specification 6.8.1.a (482/9303-01) involving failure to properly coordinate
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clearance orders.
Corrective actions included:
(1) evaluating the appropriate time to
depressurize the pressurizer relief tank during outages, (2) changing
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Procedure ADM 02-100 to prohibit the use of Target Rock Solenoid valves as
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clearance order boundaries, (3) including the unidirectional characteristics
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of solenoid operated valves in operator training, and (4) evaluating
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enhancements to the operating experience program. The licensee intends to
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evaluate improvements to information specified in night orders and
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improvements in turnover communications in response to the second release.
Night orders provide specific infermation to the operating crew from
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operations management. The licensee will report this event as LER 482/93-002
2.7 Metal Detector Calibration
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Because of concerns with the sensitivity of the metal detectors and the
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security plan calibration requirements, the inspectors reviewed the licensee's
process for calibrating the metal detectors.
On March 13, 1993, the
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inspectors observed an instrumentation and control technician check the metal
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detector calibration with the specifie f security plan calibration standard.
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The technician performed the calibration in accordance with
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Procedure INC C-3314, " Portal Metal Detectors Preventive Maintenance,"
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Revision 4.
Following calibration of the detector, the technician increased
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the detector sensitivity of the detector until the monitor could detect a
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second standard that contained less metal.
The. inspectors considered this
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enhancement to plant security to be proactive.
2.8 Failure to Maintain Containment Integrity
On March 14, 1993, following restoration from a local leak rate test, test
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personnel questioned the control room operators about the required position
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for Valve EF V085, Essential Service Water B to containment vent. As
operations personnel evaluated the required position of Valve EF V085, the
operators determined that Procedure SYS EF-420, "ESW A(B) Train Drain,"
Revision 0, left several Essential Service Water B return header vent valves
open and some containment cooler -vent valves open. Additionally, Clearance
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Order 93-0540-EF tagged the following containment penetration isolation valves
open and daenergized:
EF HV032, essential se,rvice water / containment air
cooling containment isolation; EF HV034, Essential Service Water B to
containment air coolers; EF HV046, Essential Service Water B from containment
air coolers, and EF HV048, . essential service water / containment air cooling
containment isolation.
With the vent valves and containment isolation valves open, a direct path from
the containment building to the auxiliary building existed that violated
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Technical Specification 3.9.4.
The licensee immediately established
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containment integrity by closing the containment isolation valves. The
licensee determined the root cause to be failure to assure the procedure could
be implemented as written under the existing plant conditions. The licensee
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initiated PIR OP 93-0190 to ensure that corrective actions would be
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implemented and initiated Reportability Evaluation Request 93-007 to evaluate
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reportability. The licensee corrected the Essential Service Water A procedure
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prior to draining Train A and stated they would review similar system
operating procedures for those systems that go into the containment. This
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violation of Technical Specification 3.9.4 will not be cited because the
criteria specified in paragraph VII.B.2 of the NRC Enforcement Policy were
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satisfied. The licensee appropriately identified the root cause and initiated
actions to prevent recurrence. The licensee will report this event as
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2.9 Loss of Instrument Air
On March 16, 1993, while in Mode 6, the plant experienced a loss of the
instrument air system with the reactor parJ1v defueled. The spent fuel pool
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cooling system continued to operate properly.
Ine shutdown cooling flow
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increased to 3600 gpm because air-operated flow control valves failed open.
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The licensee dispatched personnel to the air dryers / compressors to investigate
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the cause of the event.
Licensee personnel determined that solenoid valves
for the Train B instrument air dryer failed. The Train A air dryer was tagged
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out of service for maintenance.
The licensee replaced five solenoid valves
and declared the system operable after performing appropriate postmaintenance
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tests.
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The affected valves included two three-way and one four-way solenoid valves
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located on Train A and two four-way solenoid valves located on Train B.
Preliminarily, the licensee determined that sticking of the four-way solenoid
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valves contributed to this event because the four-way valve blew down instead
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of flowing to the air system. The licensee determined that the faulty four-
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way solenoid valves were unique to the air dryer system. The licensee
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initiated a hardware failure analysis to determine the root cause and
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corrective actions for these solenoid valve failures, prior to startup.
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2.10 Plant Safet_y Tours
The inspectors toured the plant accompanied by the safety coordinator to
assess:
(1) the safety condition of the plant, (2) the adequacy of plant
safety equipment, and (3) general work practices of licensee and contract
personnel. The inspectors determined the licensee maintained good
housekeeping considering the amount of maintenance activities being performed.
The inspectors inspected a number of slings in use and determined the sling
conditions met the acceptance criteria of the licensee's safety manual,
including current inspection' tags. The inspectors found personnel to be
knowledgeable concerning the use of slings. The inspectors considered the
construction and control of scaffolding to be superior, with scaffold permits
hanging at the access point. of all the scaffolds inspected. The inspectors
identified two deficiencies during the turbine building tour:
(1) a grinding
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wheel had a concave groove on the grinding wheel surface, and (2) an air hose
was connected to the service air system without a cotter pin to secure the
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hose fitting. The licensee promptly corrected both deficiencies.
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The inspectors reviewed the licensee's Occupational Safety and Health
Administration 200 Log, " Survey of Occupational Injury and Illness," noting
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that five logable events were recorded during 1993.
The inspectors reviewed
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the licensee's actions related to one of the recordable injuries and found the
actions to be thorough and comprehensive.
The safety coordinator stated that
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hand injuries constitute the bulk of the injuries experiencad at Wolf Creek
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Generating Station. Consequently, the licensee took actions to minimize
injuries by heightening personnel awareness.
For example, the licensee issued
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a pamphlet to all personnel that provided useful information on proper work
practices in a comic book style, increasing the chances that it would be read.
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2.11
Failure to Perform local Leak Rate Test
[
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On March 23, 1993, licensee personnel determined that the actuator for
Motor-0perated Valve (MOV) BG HV8105, charging pump to regenerative heat
exchanger containment isolation, was removed prior to performing an as-found
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local leak rate test as required by Technical Specification 4.6.1.2 and ANSI
Standard N45.4-1972, " Leakage Rate Testing of Containment Structures for
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Nuclear Reactors," Step 4.2.
Without taking the as-found leakage rate, the
licensee could not determine whether leakage through the valve had changed
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from the leak rate measured in December 1991. The licensee initiated
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PIR TS 93-0228 to investigate the actions leading to the event and to ensure
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corrective actions would be implemented. The licensee will report this event
as LER 482/93-005.
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The licensee determined that maintenance personnel overlooked the work
instructions that required performing an as-found local leak rate test in Work
Request 04447-93 because of personnel oversight.
,
The individual failed to perform Special Work Instruction Step 01 that
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required personnel to verify that an as-found local leak rate test was
performed. The licensee counseled the individual on the importance of
attention to detail. Also, the licensee will implement " positive discipline"
by requiring the individual to discuss the circumstances related to this
deficiency with his peers. The failure to perform the local leak rate test is
a violation of Technical Specification 4.6.1.2.
However, the violation will
not be cited because the criteria specified in paragraph VII.B.2 of the NRC
Enforcement Policy were satisfied.
Licensee personnel determined the test was
not performed. The licensee initiated an LER as required and implemented
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actions to prevent recurrence.
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2.12 High Thrust Bearing Temperature
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On March 23, 1993, following overhaul of Emergency Diesel Generator B, the
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licensee started the emergency diesel engine to perform the 24-hour
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postmaintenance test. After loading Emergency Diesel Generator B to 1600 kW,
the licenseo received a high thrust bearing temperature alarm. The
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annunciator alarms at temperatures greater than 190 F, and the licensee
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determined that the bearing temperature reached approximately 350 F.
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Operators stopped the emergency diesel generator after being notified by
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personnel who were in the room. The licensee initiated disassembly,
inspection, and reassembly of the thrust bearing in accordance with Work
Request 01784-93. The licensee determined that the inner thrust bearing was
wiped. The journal surface on the crankshaft had two bandr of deposited
bearing material 360o around the shaft and the journal surface was slightly
tempered.
Preliminarily, the licensee suspected that a loss of oil or low oil
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flow allowed the bearing surface to overheat. However, testing indicated that
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lubricating oil flowed to the bearing. The licensee determined that the
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bearing had shifted slightly around the shaft but had stopped after contacting
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the locating dowel.
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The licensee contacted an expert in hardware failure analysis to help
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determine the root cause. The licensee initiated Hardware failure
Analysis NP 93-008 to document the root cause and corrective actions. As part
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of the hardware failure analysis, the licensee will evaluate other affected
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components such as the main bearing and the bull gear. Also, the licensee
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contacted the vendor and a shaft-machining expert to help remove the tempering
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damage to the emergency diesel generator crankshaft.
From initial
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evaluations, the licensee determined the crankshaft would require machining
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until the metal was at the required hardness of 30 Rockwell C.
As documented
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in the engineering disposition to Work Request 01893-93, the licensee could
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machine the
haft by 1.5 mm initially. A hardness test will be initiated, and
,
if the required hardness is not met, the licensee will machine the shaft in
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0.5 mm increments until a total depth of 2.5 mm.
If additional machining is
necessary, another evaluation will be performed.
The inspectors will continue
,
to follow licensee activities in the next inspection period.
2.13 Clearance Order 1ssues
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On March 21, 1993, with the reactor vessel defueled, Mode E, the licensee
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di ained the reactor coolant system to half pipe to perform maintenance on
otherwise inaccessible valves. The operators performed the drain down in
accordance with Procedure SYS BB-212, " Draining the RCS to Midloop Level and
Below, fuel Off-loaaed," Revision 4.
After stabilizing the water level to
ensure the steam generator U-tubes were drained, operators noticed that the
reactor coolant system level continued to decrease. The licensee investigated
this deficiency, determining that miscoordination of Clearance
Orders 93-0651-EJ and 93-0618-EJ occurred.
Personnel should have established
Clearance Order 93-0618-EJ prior to Clearance Order 93-0651-EJ; however,
personnel established Clearance Order 93-0618-EJ first.
The inspectors determined that the implementation of the half-pipe clearance
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orders required close coordination.
Previously, the licensee established a
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single clearance order that removed all systems from service; however, to
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minimize the impact of MOV testing on clearance orders, the licensee
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specifically developed some clearance orders to support MOV testing. The
licensee issued PIR OP 93-0248 in response to this event. The PIR documented
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that the tagging group failed to ensure that the shift crews understood the
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significance of placing the half-pipe clearance orders in the correct order.
Also, the inspectors determined that Clearance Order 93-0651-EJ cautioned that
certain valves could be spened so long as they do not conflict with existing
clearances.
Procedure ADM 02-100 Step 7.1.3.4, specified that, "After the
clearance and tags have been prepared and approved, the shift
supervisor / supervising operator shall review the tagging arrangement and
,
reverify that the clearance will not adversely affect the plant." This is the
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second example of a violation of Technical Specification 6.8.1.a (482/9303-01)
involving failure to properly coordinate clearance orders.
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On March 25, 1993, control room operators noticed that the indicating lights
for MOV EJ HV88098, residual heat removal to Accumulator Injection Loops 3 and
4 isolation valve, were illuminated even though the handswitch had a Do Not
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Operate tag on the switch. Upon investigating, the licensee determined that
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electrical maintenance personnel requested that Clearance Order 93-0596-EJ be
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removed and a Human Do Not Operate control be established to allow local valve
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operation for troubleshooting. The Human Do'Not Operate control is an
individual stationed at a control device to prevent damage to equipment or
personnel injury. The individual places a placard at the control device
designating a Human Do Not Operate control is in effect.
The licensee
)
determined that a contract worker believed that a Human Do Not Operate control
could override Do Not Operate tags. Consequently, the individual disregarded
,
Clearance Order 93-0587-EJ. The licensee had the individual turn off the
breaker and counseled the individual on the proper use and significance of Do
Not Operate tags. The licensee initiated a procedure change for
Procedure ADM 02-100 to strengthen the issuance of Human Do Not Operate
controls and Do Not Operate tags. The changes specified that:
(1) equipment
will not be operated under any circumstances with a Do Not Operate tag
attached, (2) individuals must go to the control room and sign a newly created
attachment explaining the responsibilities of Human Do Not Operate controls,
and (3) possession of a Human Do Not Operate control does not give permission
to operate / change position of equipment with a Do Not Operate tag on it.
The
inspectors reviewed Procedure ADM 02-100, determining that the changes
strengthened the clearance order controls and the new attachment clearly
specified the responsibilities and limitations of a Human Do Not Operate
control.
On March 26, 1993, a worker removing MOV SJ HV127, reactor coolant system
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liquid sample outer containment isolation bypass, and MOV SJ HV005, reactor
coolant system liquid sample inner containment isolation, was sprayed with
reactor coolant fluid because the system was pressurized. The licensee
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determined that special instructions on Clearance Order 93-0377-SJ stated that
the local leak rate test performed prior to placing the clearance order would
drain the system. The licensee performed the local leak rate test for the
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affected penetration on March 13, 1993, and personnel established Clearance
Order 93-0377-SJ on March 24, 1993.
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The inspectors determined that, as originally planned, Clearance
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Order 93-0377-SJ would be placed in conjunction with the local leak rate test.
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The licensee completed the local leak rate test during defueling, but the
.
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licensee decided to place the clearance order following defueling. However,
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no thought was given to ensuring the system was drained. The licensee
,
immediately added vent and drain valves to Clearance Order 93-0377-EJ and
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drained the affected piping. The licensee removed low levels of contamination
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from the individual determining the skin dose to be 1.13 mrem, and a whole
body count identified no internal contamination.
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Following the second significant clearance or6er coordination problem in
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2 days, the Vice President, Plant Operations established an investigation team
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on March 26, 1993, in accordance with Procedure ADM 01-116. The investigation
team was chartered with reviewing several clearance order problems occurring
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since the beginning of Refuel VI. The investigation team was to determine
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common causal factors and a root cause, if possible, so that corrective
actions to eliminate the problem could be implemented. The inspectors will
continue their inspections of these deficiencies in the next inspection
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period.
2.14 Conclusions
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The licensee implemented good corrective actions in response to a loss of
a
offsite emergency preparedness notification ability. The licensee failed to
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evaluate in a timely manner whether they met Technical Specifications during
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reactor protection system response time testing.
In response to NRC concerns,
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the licensee initiated a quality assurance surveillance to determine the
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extent of the untimely initial evaluations of. Industry Technical Information
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Program items. .The implementation of 24-hour quality assurance auditor
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coverage for 3 days during the plant shutdown demonstrated a proactive quality
assurance organization. While going solid in the reactor coolant system, the
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licensee exceeded the pressurizer cooldown and heatup rates specified in
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Technical Specifications. To prevent recurrence of the temperature
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transients, the licensee will change operating procedures prior to drawing a
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bubble. During the reactor coolant system drain down, the licenset identified
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level discrepancies between the tygon hose and the midloop level
2
instrumentation. The licensee did not stop the drain down but continued using
the lowest reading instrument as the actual level. The licensee decision to
form an investigation team to evaluate gas releases inside containment was
a
commendable.
Personnel implemented an extensive and thoroug!, evaluation
identifying the root cause and recommending corrective actions.
Increasing
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the metal detector sensitivity demonstrated the licensee's proactive attitude
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in security. The licensee failed to maintain containment closure as required
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by Technical Specification 3.9.4 when operators performed a procedure in a
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mode other than intended that resulted in a noncited violation. The
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inspectors considered the licensee attitudes about personnel safety to be
proactive.
Housekeeping was found to be good with the licensee maintaining
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excellent control of plant scaffolding. During this period, licensee
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personnel failed to perform an as-found local leak rate test as specified in
Technical Specification 4.6.1.2 that resulted in a noncited violation.
The
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inspectors identified a violation with two examples of improperly coordinated
clearance orders.
The licensee had a second gas release in containment
because of improper turnover, and the licensee continued to drain down the
reactor coolant system in Mode E because clearance orders were not placed in
the correct order.
The licensee initiated an investigation team to identify
causal factors and a common root cause of several clearance order issues that
occurred over a 3-week period.
3 MAINTENANCE OBSERVATIONS (62703,62700)
The purpose of inspections in this area was to ascertain whether maintenance
activities on safety-related systems and components were conducted in
accordance with approved procedures and Technical Specifications. Methods
used in this inspection included direct observations of maintenance
activities, personnel interviews, and records review.
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3.1 Out-of-Calibration Measuring and Test Equipment
The licensee generated PIR 93-0151, dated March 6, 1993, that identified
93 out-of-calibration measuring and test equipment evaluations that were
significantly backlogged. The inspectors expressed concern because of the
quantity and age of the backlogged out-of-calibration evaluations, and the
inspectors questioned the operability of safety-related equipment required in
Mode 6.
The licensee determined that 62 out-of-calibration evaluations
affected safety-related components, with some dating back over 1 year.
The
immediate corrective actions included prioritizing the backlogged evaluations
and applying maintenance support resources during Refuel VI to decrease the
backlog.
Long-term corrective actions included determining acceptable backlog
levels, identifying the number of personnel needed to maintain these levels,
providing maintenance management with monthly backlog aging reports, and
generating guidance for performing evaluations.
The inspectors reviewed Procedure ADM 08-210, " Calibration and Control of
Maintenance and Modification Measure and Test Equipment (M&TE)," Revision 11.
This procedure specified the steps to be taken when personnel identified
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measuring and test equipment out of tolerance during recalibration. The
inspectors noted that the procedure did not specify a time limit for
evaluating the effects of the out-of-calibration measuring and test equipment.
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The inspectors determined that the licensee generated eight work requests from
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the evaluations of the safety-related uses of measuring and test equipment
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found out of calibration.
The licensee stated that they had reviewed all the
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nonsafety out-of-calibration applications and determined that none affected
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plant safety. During the discussion, the licensee stated that the long-term
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corrective actions to control the backlog will be determined and possibly in
place by the end of the current refueling outage.
The licensee completed
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their reviews of the nonsafety applications related to out-of-calibration
evaluations by March 27, 1993.
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The inspectors reviewed the licensee dispositions for the eight work requests
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generated from the out-of-calibration measuring and test equipment
!
evaluations. The inspectors determined that the licensee appropriately
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dispositioned six of the work requests "use as is."
Work Request 01465-93
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concerned the potential overtorquing of the housing bolts for a reactor
coolant pump bearing oil filter. The system engineer determined that the
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cover bolts were torqued beyond their allowable stress values and would be
repl aced. The inspectors agreed with the engineering disposition. Work
Request 01467-93 concerned the potential overtorquing of the bonnet bolts for
the Containment Spray Pump A to containment spray nozzles check valve. The
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system engineer calculated that the bolting was potentially overstressed.
The
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inspectors concurred with the engineering disposition that required all of the
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bonnet bolts to be replaced during Refuel VI.
,
The inspectors determined from discussions with quality assurance personnel
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that they identified that the out-of-calibration maintenance and test
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equipment backlog could affect equipment operability in November 1992.
In the
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executive summary of the audit report, quality assurance identified the
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timeliness of technical evaluations by maintenance support to be poor. The
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licensee stated that the ASME program quality assurance audit scheduled for
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the fall of 1993 will review the maintenance department measuring and test
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equipment backlogs.
Also, the licensee stated that they might perform a
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surveillance of measuring and test equipment backlogs this year. The
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inspectors considered the licensee's failure to act on the quality assurance
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department recommendations a weakness.
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3.2 Main Steam Safety Valve Testing
On March 3, 1993, the inspectors observed vendor personnel perform a trevitest
on Main Steam Safety Valve AB V057. The trevitest method uses hydraulics to
begin the valve lift that is completed by main steam pressure.
From the data
collected, the technicians calculated the steam pressure that would have
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lifted the safety valve. The inspectors observed a sixth and second
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consecutive successful test of Main Steam Safety Valve AB V057 with the
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acceptance criteria being two consecutive valve lifts within the specified
setpoints. Because this valve was a test failure (the first two valve lifts
!
failed), the licensee increased their test sample by four predetermined
valves. During this outage, the licensee tested ten main steam safety valves
with only one test failure. The inspectors verified that the vendor personnel
performed the testing in accordance with their procedures, that the test
equipment was within calibration and properly connected, and that two
consecutive valve lifts occurred prior to declaring an acceptable test.
The engineering disposition for Work Request 01097-93 determined that, since
Main Steam Safety Valve AB V057 lifted at 1236 psi, which was well within the
designed rating for the main steam lines of 1303 psi, the valve would still
have performed its designed function of preventing the main steam line from
overpressurizing.
Further, the licensee determined that complete failure of
this valve would have limited the ability of the main steans safety valves to
release 80 percent instead of the required 81.3 percent.
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3.3 Conclusions
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The inspectors determined that the licensee had a significant backlog of
measuring and test equipment out-of-calibration data sheets awaiting
!
evaluation. After the inspectors expressed concern because of the potential
effects on equipment operability, the licensee increased their evaluation
efforts, determining that no out-of-calibration evaluations affected equipment
operability. The inspectors considered the failure of the maintenance
,
organization to respond to quality assurance audit observations 4 months
earlier to be a weakness. The licensee determined that one out of 10 main
steam safety valves failed to lift at the required setpoint during insitu
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trevitesting. The licensee determined that no consequences to the plant would
occur had the relief valve been required to actuate.
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4 SURVEILLANCE OBSERVATIONS (61726)
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The inspectors reviewed this area to ascertain whether surveillance of safety-
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related systems and components was conducted in accordance with Technical
Specifications and approved procedures.
4.1 Reactor Coolant Drain Tank Flow T-ansmitter Calibration
On March 9, 1993, the inspectors observed instrumentation and control
technicians perform a calibration of Flow Transmitter HB FT-1009, reactor
coolant drain tank pump discharge flow. The technician performed the
calibration in accordance with Procedure INC C-1003, " Calibration of
Transmitters," Revision 4.
For the field calibration, the technicians used a
,
data sheet that specified the required outputs for a given input, including
the instrument accuracy. The technicians properly connected and utilized
calibrated test equipment.
The technicians did not have the procedure present since the area was
contaminated.
From review of the procedure, the inspectors determined that
the calibration was performed in accordance with the procedure.
The procedure
specified shift supervisor approval prior to starting, recording of test
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instruments, instrument accuracy, and acceptance criteria.
The procedure
i
specified that technicians may vary the zero, span, and linearity, as
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necessary, to bring the instrument into calibration.
4.2 Pressure Transmitter Calibration
On Mard 12, 1993, the inspectors observed an instrumentation and control
technician perform Procedure STS 10-530B, " Channel Calibration RCS Wide Range
Pressure Transmitter," Revision 5.
The technicians maintained good
communications with the personnel at the pressure instrument.
Concurrent with
the surveillance, the inspectors determined that the operators were confused
because their temperature indications became erratic.
The procedure required the tecnnician to place various bistables in test,
removing the respective functions from the circuit. When the technicians
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placed Card 861, BS-1 bistable in test, the wide range temperature being
monitored in the control room became erratic.
The inspectors determined that
this response was normal because the computer point no longer received
temperature data from the field sensor. The inspectors interviewed personnel
and learned that, previously, the operators did not use the computer to
monitor the temperature.
Temperature indicators that did not receive computer
inputs remained constant. The installation of the new computer, 2 years
earlier, enabled the licensee to diversify their monitoring capability. The
licensee initiated PIR.TS 93-0192 to correct the problem and determined that
the temperature instrument input to the computer could remain in service
during future surveillances.
4.3 Conclusions
The inspectors determined that instrumentation and control technicians
maintained excellent coordination during surveillance tests. The technicians
performed testing in accordance with procedures and used calibrated test
equipment.
5 RELIABLE DECAY HEAT REMOVAL DURING OUTAGES (2515/113)
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The inspectors evaluated licensee activities for assuring that decay heat
removal was available as required during the outage.
5.1
Inspection
The inspectors reviewed the outage schedule and interviewed personnel,
determining that the licensee ensured that one or both of the residual heat
removal systems were available at all times. Also, the licensee ensured that
for the inservice train of residual heat removal both onsite and offsite power
sources were available.
The licensee conducted a shutdown risk assessment in accordance with
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Procedure ADM 01-249, " Outage Risk Management," Revision 0, and developed
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contingency plans for periods of high risk based upon the outage schedule.
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The licensee developed the outage schedule in a manner to assure maximum
availability of decay heat removal and electrical power.
During the risk
'
evaluation, the licensee ensured that one train of residual heat removal was
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available whenever fuel was in the vessel and that two offsite and one onsite
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power source was available. Also, the licensee established a contingency plan
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to place flagmen in the switchyard during switchyard maintenance.
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The licensee does not use natural circulation as a normal, planned method to
assure core cooling.
Procedure OFN EJ-015, " Loss of RHR During Decreased RCS
Inventory or Refueling," Revision 0, and Procedure OFN BB-031, " Shutdown
Emergency," Revision 0, specify conditions required to be monitored to assure
natural circulation is taking place, if required.
The inspectors verified
that two offsite power sources and an emergency diesel generator were
available at all times when residual heat removal was required. When the
licensee performed battery testing and maintenance, the licensee powered the
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affected DC bus from a backup battery charger.
The licensee trained operators
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on Procedure EMG E-0, " Reactor Trip or Safety Injection," Revision 3.
This
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procedure specified the appropriate sequence for adding safety-related
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equipment whenever the equipment fails to load automatically.
The inspectors verified that the licensee considers the emergency diesel
generators to be inoperable when the field flashing source is removed from
service. The licensee has proceduralized their nonstandard electrical lineups
for each type of bus (i.e., 4160 kV, 480 V, etc.).
The procedures specify
that the maximum load to be carried during the lineup shall not exceed the
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maximum load of either bus.
The inspectors reviewed the safety evaluations
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for a temporary modification during Refuel IV that was proceduralized for this
outage. The inspectors determined that the evaluation was properly conducted.
5.2 Conclusions
The inspectors determined that the licensee implemented conservative actions
during Refuel VI to assure they maintained reliable decay haat removal.
The
licensee assessed shutdown risk and developed contingency plans for periods of
high risk. Also, the licensee minimized the unavailability of electrical
power.
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6 REFUELING ACTIVITIES (60710,86700)
The inspectors reviewed licensee activities during the refueling outage to
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verify that their performance met regulatory requirements. The inspectors
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reviewed numerous documents during review of this area as listed in
Attachment 2.
6.1 Refueling Activities
The inspectors determined that the licensee established surveillance
requirements for verifying:
boron concentration, refueling crane interlocks,
operability of ventilation and filters, communications, fuel pool levels,
injection flow paths, and containment integrity. The inspectors verified that
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the required Technical Specifications surveillances were completed within the
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appropriate time frames prior to CORE ALTERATIONS. The inspectors verified
that the licensee performed the required daily and weekly Technical
Specifications surveillances.
The inspectors verified that the licensee maintained proper staffing in the
control room and on the refueling floor.
Also, the inspectors verified that
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qualified contractor personnel performed the fuel movement and vessel
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di sassembly. The inspectors determined that the contractor's training program
provided good guidance and that the licensee verified the adequacy of the
training provided. The inspectors determined that the licensee established
and enforced good housekeeping and loose object control in the refueling and
spent fuel pool areas.
The data below indicates the licensee's readiness to implement Refuel VI work
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activities at the beginning of the outage and at the end of the inspection
period. The information in the table is listed in percent.
3/4/93
3/27/93
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Plant Modification Requests:
Complete
--
62
Ready to Work
74
38
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Package Preparation
12
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Hold Parts
9
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Other
5
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MOV Plant Modification Requests:
Ready to Work
64
100
Package Preparation
8
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Hold Parts
28
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Work Requests:
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Complete
--
15
Ready to Work
73
61
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Package Preparation
17.5
19
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Hold Parts
7.1
3
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Other
2.4
2
The inspectors determined that the licensee made significant progress to get
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ready for Refuel VI from February 13 to March 4,1993 (refer to NRC Inspection
!
Report 482/93-01).
From discussions with personnel, the inspectors determined
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that packages not yet ready to work were for upcoming outage windows.
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6.2 Spent Fuel Pool Activities
The inspectors reviewed licensee activities related to a potentially damaged
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rod control cluster assembly. While inserting Rod Control Cluster
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Assembly RSIO into the spent fuel pool, the assembly stopped prior to entering
the storage rack. The licensee attempted a second insertion without . success.
The licensee determined that a hole in the insert plate over the storage rack
was not drilled. The licensee moved the rod control cluster assembly into a
different storage location and will remove the defective plate following the
outage. The licensee visually inspected the rod control cluster assembly to
ensure that welded connections were intact, the condition of the end plug and
the rod, and overall visual appearance of the rod control cluster assembly.
The licensee determined the rod control cluster assembly could be used as is.
The inspectors monitored licensee activities related to fuel movement.
During
the fuel shuffle of the burnable poison rod assemblies, the inspectors noted
that mechanical stops prevented the overhead crane from passing over fuel
storage positions. The inspectors determined that the licensee maintained
spent fuel pool level above the minimum requirement, as noted by visual
inspection of the spent fuel pool level indication. The licensee maintained
spent fuel pool temperature at 100oF. The inspectors considered overall
housekeeping in the area to be good with no items that would interfere with
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the proper operation of the fuel handling machine nor that could fall into the
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spent fuel pool.
Licensee personnel operating the fuel handling equipment
were knowledgeable of their responsibilities.
The inspectors verified that -
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the procedures used to perform the burnable poison rod fuel assembly shuffle
were properly reviewed and approved.
In addition, the inspectors verified
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that personnel maintained an accurate record of the shuffle.
6.3 Reactor Coolant System Vacuum Venting
The inspectors reviewed the licensee activities performed to prepare for the
vacuum venting of the reactor coolant system since this will be the licensee's
first attempt using this method. The licensee established a procedure that
uses an eductor to pull a vacuum in the reactor coolant system. The
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eductor:
(1) vents the reactor coolant system in 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> instead of the
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6 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> needed without a vacuum, (2) extends the life of reactor coolant
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pump motors and seals by decreasing the number of pump starts needed to remove
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air from steam generator tubes, and (3) decreases the potential for
transgranular stress corrosion cracking in spare reactor vessel head
penetrations. The licensee functionally tested the vacuum vent system on
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February 26, 1993.
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The licensee determined the required reactor coolant system temperature and
water level, components required to be isolated, and components that should
remain in service. After the vacuum pressure remains constant for
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150 minutes, the operators will increase reactor coolant system water level at
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60-80 gpm.
Chemistry personnel will sample the reactor coolant for dissolved
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oxygen prior to vacuum venting and prior to the primary becoming solid to
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evaluate the ability of the system to remove dissolved oxygen.
Previously, the procedure for venting of the reactor coolant system required
filling and pressurizing the reactor coolant system to approximately 400 psi,
bumping a reactor coolant pump to remove air from the associated steam
generator tubes, reducing reactor coolant system pressure to 50 psi, and
venting the reactor coolant system. This process of pressurizing, reactor
coolant pump bumping, depressurizing and venting was repeated several times
with the remaining reactor coolant pumps. The vacuum vent system will remove
air and noncondensibles from the vessel, steam generator tubes, and the
pressurizer within 2 to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> with reduced reactor coolant pump starts,
which will minimize equipment maintenance costs.
In February 1992 the licensee repaired spare Reactor Vessel Head
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Penetrations 24 and 25 because of leaking canopy seal welds. During this
outage, the licensee determined that spare Reactor Vessel Head Penetration 29
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will require repair because of canopy seal weld cracking. The licensee
determined the postulated cause to be transgranular stress corrosion cracking
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at the canopy seal weld. Trapped oxygen could not be vented through the head
vent because the air pocket is higher than the head vent. After plant heatup,
the reactor coolant system pressure and temperature adds the other two
components required to initiate stress corrosion cracking.
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The inspectors reviewed the 10 CFR Section 50.59 evaluation and Configuration
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Change Package CC00246 and determined that system engineering had developed a
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detailed method of vacuum venting the reactor coolant system. The evaluation
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reviewed the effects on all primary system components and specified in detail
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the method to be followed.
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6.4 Failed Fuel Rod
On March 16, 1993, as personnel lifted fuel Assembly H10 in Location H-7
during defueling, the spotter noticed that a fuel rod piece was bridging the
fuel assemblies between Locations H-6 and H-7.
The refueling personnel
stopped the defueling with Assembly H10 in location H-7 lifted approximately
71/2 inches vertical and 3 inches away from Assembly F67 in Location H-6.
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The licensee used an underwater camera to determine that the fuel rod piece
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came from Assembly F67.
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The licensee developed a plan to use remote, pneumatic operated vice grips to
latch onto the fuel rod piece. The licensee placed a 2 by 5 foot catch pan
under the raised assembly to catch the fuel rod piece if it fell. When
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personnel attempted to capture the fuel rod piece in the vise _ grips, the fuel
rod piece fell below the core plate. The licensee moved Assembly F67 into the
spent fuel pool. After defueling the reactor, the licensee implemented a
foreign object search and retrieval effort and recovered the fuel rod piece.
After recovering the fuel rod piece, personnel used a vacuum to clean and
remove all small particles possible. The licensee determined the fuel rod
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piece was 12 inches long.
The licensee reviewed films of the failed fuel rod
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sections and inspected the vessel interior.
Since the licensee identified no
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loose pellets during the foreign object search and retrieval effort, the
licensee had some confidence that all pellets were accounted for.
The
licensee reported this issue in accordance with 10 CFR Section 50.72 and will
issue LER 482/93-004.
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The licensee identified three fuel assemblies. Assemblies F43, F54, and F67,
that had fuel clad failures in 14 fuel rods. The licensee discharged all the
fuel assemblies. During the previous outage, the licensee had identified a
similar fuel rod failure.
All the F-type assemblies manufactured on the same
fixture were discharged (refer to LER 91-019 and NRC Inspection
Report 50-482/91-31).
Preliminary evaluations indicated that the f ailure
mechanisms could be similar. The NRC and licensee personnel will meet in the
near future to discuss these additional failures.
6.5 Conclusions
The inspectors determined that the licensee programs for conduct of Technical
Specifications surveillances assured that the applicable Technical
Specifications for refueling were met. The licensee had excellent procedures
for controlling the refueling. The licensee implemented the outage in a
controlled manner that ensured maintenance and modifications could be
implemented. The licensee identified that they had a failed fuel rod, but a
root cause had not yet been determined.
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7 FOLLOWUP ON CORRECTIVE ACTION FOR VIOLATIONS (92702)
7.1
(Closed) Violation (482/9126-02):
Containment Purge Isolation and
Control Room Ventilation Caused by High Gaseous Activit_y Durinq
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Containment Purge
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On October 2, 1991, after initiation of a containment purge, the containment
purge and control room ventilation systems isolated because of high gaseous
activity in the containment purge system.
The licensee determined that
operators failed to use Procedure 0FN 00-019 " Loss of Instrument Air,"
Revision 8, earlier that day when restoring from a loss of instrument air to
the containment building. After initiating the containment purge, the
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operator noticed that Damper GT HZ-8, containment purge exhaust, was closed.
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When the operator opened the damper, a containment purge isolation signal was
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received. The operators restored from the containment purge and control room
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ventilation system isolations. The licensee sampled the containment air,
determining that no airborne activity existed inside the containment building.
Because of a previous, similar occurrence, the licensee evaluated alternate
methods for venting the reactor coolant system.
The inspectors verified that the licensee established an alternate method for
venting the reactor coolant system in Procedure GEN 00-007. Additionally, the
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inspectors determined that the licensee was completing a review of all
components inside containment serviced by instrument air. The licensee
intends to issue a controlled document that lists the instrument air loads
located in each building to aid operators during restoration of components
serviced by instrument air.
7.2
(Closed) Violation (482/91202-01):
Inadeouate Procedure
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NRC issued this violation because Procedure ALR 00-128C, "TDAFP BRG Oil Temp
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Hi," Revision 3, incorrectly referenced instrumentation to be used in
determining intermediate and long-term operator actions when operators
responded to high turbine-driven auxiliary feedwater pump lube oil
temperatures.
The procedure referenced bearing temperatures and not the lube
oil temperature.
Also, the procedure did not describe that lube oil cooler
outlet temperatures could only be monitored locally.
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The inspectors verified that the licensee modified Procedure ALR 00-128C.
The
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licensee implemented a program to improve their alarm response procedures as
required by Management Action Plan Issue V.
The licensee transferred the
procedure upgrades to Performance Enhancement Program Action Plan 3.3.2.
The
inspectors determined that the alarm response procedure upgrades should be
completed by September 30, 1993. The licensee reviewed the alarm response
procedures to ensure that existing guidance was usable and technically
correct. The procedure upgrade group corrected identified deficiencies such
as improper numbering, alarm windows without response procedures, and alarm
procedures written for nonexistent windows. Approximately 20 minor
deficiencies remain to be corrected.
The licensee should correct the
deficiencies by April 30, 1993.
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The inspectors determined that out of 1400 alarm response procedures,
personnel had drafted 683 procedures and had placed 100 procedures in the
review / approval process. The inspectors determined that the licensee
implemented a well-controlled, detailed process for upgrading the alarm
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response procedures.
The inspectors walked through the development of two
alarm response procedures and determined that the licensee used good
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verification and validation techniques.
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7.3 (Closed) Violation 482/9208-01:
Inadvertent Release of Radioactive
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Gaseous Waste Due to inadeauate Procedures
On April 23, 1992, as a radwaste operator placed Waste Gas Decay Tank 4 in
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service, an inadvertent release of radioactive gas occurred because of
inadequate procedures.
The licensee determined that Procedure SYS HA-200,
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" Waste Gas System Startup and Shutdown," required the inlet pressure control
valve to be in manual, which immediately pressurized the hydrogen recombiner.
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Prior to overhauling the compressors, the licensee operated the system
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manually to compensate for the poor discharge pressure. After installing new
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compressor internals, the licensee failed to change the system operation to
automatic. Consequently, Procedure SYS HA-200 did not provide sufficient
steps to prevent the rapid pressure rise.
Additionally, with the recombiner
sample isolation valves open, as specified by Procedure SYS HA-205, " Gaseous
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Radwaste System Gas Analyzer Racks (HA-161/HA-162) and Catalytic Hydrogen
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Recombiners (SHA01A/SHA01B) Operations," a direct path existed for release of
waste gas into the radwaste building ventilation.
The licensee implemented actions to preclude future violations. The licensee
revised Procedure SYS HA-200 to ensure that the waste gas system pressure
control valve is in automatic to prevent rapid pressurization. Additionally,
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the licensee revised Procedure SYS HA-205 to ensure the analyzer rack
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instrument sample isolation valves remain closed until the system is
recirculating and all parameters are stable. The inspectors found the
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corrective actions to be acceptable.
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7.4
(Closed) Violation 482/9208-02:
Performance of Maintenance Activities on
Boric Acid Filter Drain Valve BG V322 Without an Appropriate Work Reauest
On May 21, 1992, the licensee identified a decrease in boric acid tank levels
because Valve BG V322, boric acid filter drain, was not fully closed. The
licensee determined that a bolt on the valve-to-reach rod attachment contacted
a support, preventing full closure of Valve BG V322.
Subsequently, mechanical
maintenance personnel adjusted the bolt on the reach rod attachment without an
appropriate work request.
The licensee attributed the root cause of this event to be a personnel error
for failing to follow Procedure ADM 01-057, " Work Request," which required
issuance of a work request to document and control work performed on plant
systems.
In addition, the licensee determined that the postmaintenance
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testing specified on Work Request 02652-92 was not effective.
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The licensee completed a review session on the use of Procedure ADM 01-057 and
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the work request process with the involved mechanical maintenance personnel.
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Additionally, the postmaintenance testing requirements as specified in
Procedure ADM 01-057 were revised. The postmaintenance test block on the work
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request form was changed to require more specific information on the test,
including test description, responsible group, acceptance criteria, and
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results. Maintenance management and supervision plan to continue monitoring
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the effectiveness of postmaintenance testing.
7.5 (Closed) Violation 482/9212-02:
Failure to Meet Technical Specifications
Surveillance Schedule Reauirements for Emergency Diesel Generator B and
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Containment Airlocks
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On June 8,1992, while performing the Technical Specifications operability
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test for Emergency Diesel Generator B, operators stopped the emergency diesel
generator because of high oil and bearing temperatures. This was the fifth
valid failure experienced by this emergency diesel generator within the last
100 tests. On June 26, 1992, the licensee determined that they failed to
increase the surveillance testing to once per 7 days as required by Technical
Specifications. On July 7, 1992, the licensee noted that
Procedure STS PE-14A, " Containment Air Locks Test (Personnel Hatch)," and
Procedure STS PE-14B, " Containment Air Locks Test (Emergency Hatch)," were
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performed past their assigned due date.
The licensee determined that they failed to meet Technical Specifications
surveillance schedule requirements for Emergency Diesel Generator B because of
cognitive personnel error and procedural weakness. A licensee engineer failed
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to formally review the number of failures in the last 20 and 100 valid tests
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immediately following the valid failure on June 8,1992. Also,
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Procedure ADM 01-0244, "EDG Reliability Monitoring Program," required the
number of failures in the last 20 valid tests to be listed on a form for all
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valid failures.
Procedure ADM 01-244 did not list the failures in the last
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100 valid tests since it was not developed to verify compliance with Technical
Specifications
The licensee determined that a change to the computerized scheduling program
resulted in a failure to meet Technical Specifications surveillance schedule
requirements for the containment airlock tests. The licensee determined that,
upon altering the surveillance scheduler program to eliminate the
3.25 surveillance test limit that was removed from Technical Specifications,
they added a 25 percent extension to the containment airlock test due dates.
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Consequently, the scheduler automatically calculated the next late date
inappropriately since the 25 percent extension is not applicable to
Procedures STS PE-014A and -B.
The licensee revised Procedure ADM 01-244 on August 19, 1992, to monitor
Technical Specifications Table 4.8-1 failures and provided requirements to
complete the form within 5 days. This should ensure the 7-day testing
frequency is met if accelerated testing is required. Also, the licensee
modified the form to document all valid tests to maintain a better awareness
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of the failures. A computer program was written to be used on the
computerized scheduling database for modifying production data.
In addition,
a quarterly comparison will be made of the information currently in the
surveillance database compared to what was in the database the previous
quarter.
8 FOLLOWUP (92701)
8.1
Inspection Followup Items
8.1.1
(Closed) Inspection Followup Item 482/9202-01:
Permanent Cavity
Seal Ring
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During a forced outage in March 1992, the licensee determined that borated
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polyethylene from within the permanent cavity seal was deposited on the
reactor coolant system piping.
Investigation into why the barated
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polyethylene melted determined that the heat source was inleakage of air at
the corners of the vertical and horizontal insulation.
As corrective actions,
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the licensee filled the corner gap with additional insulation, placed
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insulation between the reactor vessel and the permanent cavity seal ring,
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redistributed the air flow to enhance cooling, and placed stainless steel
sheets over reactor coolant system piping to preclude the borated polyethylene
from dropping on the piping.
The inspectors reviewed the results of the inspections performed during
Refuel VI and interviewed licensee personnel, determining that the borated
polyethylene did not flow from the permanent cavity seal. Throughout the
operating cycle, the inspectors verified that health physics radiation surveys
indicated no increasing trend of radiation levels above the permanent cavity
seal that would indicate the borated polyethylene was melting.
The radiation
surveys indicated that radiation levels were reduced more by the permanent
cavity seal than they had been by the removable cavity seal.
The licensee implemented Temporary Modification 93-007-BB during Refuel VI to
install dosimeters that will monitor the relative radiation levels above and
below the permanent cavity seal. The licensee installed four additional
dosimeters at various locations to determine radiation levels over one
operating cycle. The licensee expects the monitors to verify that the
radiation levels have decreased inside containment. This should increase the
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lifetime of environmentally qualified equipment.
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8.1.2
(Closed) Inspection Followup Item 482/9301-02:
Differential Relay
Testing
The licensee had identified jumpers installed from Phase C to ground on a
terminal board for the Emergency Diesel Generator B differential current
relay. The inspectors initiated this open item to follow the licensee's
activities to inspect other safety-related breaker cubicles for installed
jumpers. During the Refuel VI Train B 4160 kV bus outage, the licensee
inspected each of the 4160 kV breaker cubicles. Additionally, the licensee
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initiated Work Request 01684-93 to inspect terminal boards in the 4160 kV
Train A breaker cubicles.
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8.2 10 CFR 21 Report
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(Closed) 10 CFR 21 Report:
Limitorque Part 21 Notification Dated December 11,
1990:
SMB-00 Torque Switch Roll Pin f ailures During Declutching Operations
The inspectors reviewed this issue in NRC Inspection Report 50-482/92-31,
Section 3.3.
The licensee will replace the torque switches in the affected
valves by the end of Refuel VI.
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9 IN-0FFICE REVIEW OF LICENSEE EVENT REPORTS (90712)
The inspectors reviewed the following LERs to determine that the corrective
actions discussed in the report were appropriate and completed.
9.1
(Closed) LER 482/91-013:
Inadequate Electrical Separation
9.2 (Closed) LER 482/91-018:
Containment Purge Isolation and Control Room
Ventilation Caused by High Gaseous Activity During Containment Purge
9.3
(Closed) LER 482/92-001:
Failure to follow Procedures Could Have Caused
Both Intermediate Range Channels to be Inoperable During Physics Testinq
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9.4
(Closed) LER 482/92-004:
Feedwater Isolation Signal Actuation Resulting
From a Lead to a Logic Card in the Solid State Protection System
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inadvertently Remaking Contact
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9.5 (Closed) LER 482/92-011:
Personnel Error in not Increasing Emergency
Diesel Generator Testing Frequency Following a Valid Failure Results in a
Technical Specifications Violation
9.6 (Closed) LER 482/92-012:
Error in Surveillance Database Results in a
Failure to Meet Technical Specifications Surveillance Requirements
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ATTACHMENT 1
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1 PERSONS CONTACTED
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P. D. Adams, Supervisor, Reactor Engineering
R. S. Benedict, Manager, Quality Control
V. J. Canales, Supervisor, Maintenance Support
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T. F. Deddens, Manager, Outage
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M. E. Dingler, Manager, Nuclear Plant Engineering Systems, Support
C. W. Fowler, Manager, Maintenance and Modifications
R. B. Flannigan, Manager, Nuclear Safety Engineering
D. E. Gerrelts, Manager, Instrumentation and Control
N. W. Hoadley, Manager, Equipment Engineering
J. W. Johnson, Manager, Security
R. L. Logsdon, Manager, Chemistry
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0. L. Maynard, Vice President, Plant Operations
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R. A. Meister, Senior Engineer Specialist, Licensing
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K. J. Moles, Manager, Regulatory Services
T. S. Morrill, Manager, Radiation and Protection
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C. E. Parry, Director, Performance Enhancement Program
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G. J. Pendergrass, Supervisor, Inservice Testing
L. D. Ratzliff, Supervisor, System Engineering
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F. T. Rhodes, Vice President, Engineering
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C. E. Rich, Jr., Supervisor, Electrical Maintenance
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T. L. Riley, Supervisor, Regulatory Compliance
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B. B. Smith, Manager, Modifications
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C. M. Sprout, Manager, System Engineering
J. D. Stamm, Manager, Plant Design Engineering
M. G. Williams, Manager, Plant Support
The above licensee personnel attended the exit meeting.
In addition to the
personnel listed above, the inspectors contacted other personnel during this
inspection period.
2 EXIT MEETING
An exit meeting was conducted on April 1, 1993. During this meeting, the
inspectors reviewed the scope and findings of the report. The licensee did
not identify as proprietary any information provided to, or reviewed by, the
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inspectors.
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ATTACHMENT 2
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Documents Reviewed
ADM 01-108, " Outage Planning and Implementation," Revision 8
ADM 01-248, " Conduct of Infrequently Performed Tests or Evaluations,"
Revision 0
ADM 01-249, " Outage Risk Management," Revision 0
FHP 02-001, " Refueling Procedure," Revision 12
FHP 02-004, " Refueling Cavity Exclusion Area," Revision 1
FHP 02-011, " Fuel Siiuffle and Position Verification," Revision 13
FHP 03-006, " Fuel Transfer System Operating Instructions," Revision 4
FHP 03-007, " Spent Fuel Pool Bridge Crane Operating Instructions and
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Daily Checks," Revision 15
CEN 00-007, "RCS Drain Down," Revision 17
MGE TP-004, " Temporary Power For NB02 Maintenance Bus Outage,"
Revision 0
ML TRN-001, " Fueling Operations Personnel Qualifications," Revision 4
OFN BB-031, " Shutdown Emergency," Revision 0
OFN EJ-015, " Loss of RHR During Decreased RCS Inventory or Refueling,"
Revision 0
OFN KE-018, " Fuel Handling Accident," Revision 0
Special Order 12, " Fuel Handling Equipment Qualifications," Revision 6
Standing Order 21, " Control of Switchyard Maintenance," Revision 7
STS BB-Oll, " Reactor Coolant System and Pressurizer Heatup/Cooldown
Surveillance," Revision 10
STS CR-002, " Shift Log for Modes 4, 5 and 6," Revision 16
STS PE-023, " Fuel Building Negative Pressure Test," Revision 4.
(Train A performed in February 1993 on an 18-month frequency as
specified by Technical Specification 4.9.13.g.2.)
SYS BB-212, " Draining the RCS to Midloop Level and Below Fuel
Offloaded," Revision 4
Technical Specification Interpretation 010-89, " Tech Specs Application
with No Fuel in the Vessel"
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