IR 05000313/1993005
| ML20045F534 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 06/30/1993 |
| From: | Stetka T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20045F531 | List: |
| References | |
| 50-313-93-05, 50-313-93-5, 50-368-93-05, 50-368-93-5, NUDOCS 9307080005 | |
| Download: ML20045F534 (29) | |
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APPENDIX U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Inspection Report:
50-313/93-05 50-368/93-05
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Operating Licenses:
DPR-51 NPF-6
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Licensee:
Entergy Operations, Inc.
Route 3, Box 137G
Russellville, Arkansas' 72801 Facility Name:
Arkansas Nuclear One (ANO), Units 1 and 2 Inspection At:
Russellville, Arkansas
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Inspection Conducted: April 18 through May 29, 1993 l
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Inspectors:
L. Smith, Senior Resident Inspector
S. Campbell, Resident Inspector A. Gaines, Resident Inspector
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Accompanying personnel:
K. Weaver, Engineering Aide Approved:
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. T Stetka,' Chief, Pr ctpctionD Date
Inspection Summary l
Areas Inspected (Units 1 and 2): This routine resident inspection addressed
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onsite followup of events, operational safety verification, engineered safety feature system walkdown, monthly maintenance observation, bimonthly surveillance observation, occupational radiation exposure, followup on corrective actions for violations and deviations, and onsite followup of
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licensee event reports.
Results (Unit 1):
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The improper temporary storage of self contained breathing apparatuses
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resulting in a plant transient was a weakness (Section 2.9).
Results (Unit 2):
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The continued implementation of the systematic control of outage
risk evolutions (SCORE) card program during the planning and
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performance of Steam Generator Inspection Outage 2P-93-01 to l
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s control risk during shutdown conditions was viewed as a strength.
9307080005 930702
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PDR ADDCK 05000313
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The prebriefing and oversight provided the operating crew associated with the Unit 2 plant shutdown were also viewed as a strength.
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Oversight of the reactor coolant system (RCS) during draining and while
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at reduced inventory was excellent (Section 2).
Results (Units 1 & 2)
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Based on a review of information from the condition reporting system, I
control of contractors has improved steadily since 1990 (Section 2.12).
Management support for the Radiation Protection program was very
good (Section 6.1).
The audit and surveillance. program for the radiation protection i
area was excellent (Section 6.1),
j The training program for radiation workers and general employees
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was effective (Section 6.2).
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A noncited violation was identified for an unposted and unguarded
Iccked high radiation area.
The licensee made long-term
corrective action commitments for the noncited violation i
(Section 6.3).
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A noncited violation was identified for failure to inspect and
operationally check all respiratory protection equipment at least i
30 days prior to use. The licensee made long-term eorrective i
action commitments for the noncited violation (Sect on 6.4).
A good radiation area survey program was implemented
(Section 6.5).
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A weakness was noted for the failure to provide a step-off pad for
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an entry and exit point to a contaminated area and for personnel entering a contaminated area at a place other than at the step-off pad (Section 6.5).
Management involvement and support for the as low as reasonably i
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achievable (ALARA) plan was excellent (Section 6.6).
The ALARA suggestion program was very good (Section 6.6).
- Summary of Inspection Findings:
Inspection Followup Item 313/9305-01 was opened (Section 3.1).
- Two noncited violations were identified (Sections 6.3 and 6.4).
- Violation 368/9225-01 was closed (Section 7.1).
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Attachment:
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Persons Contacted and Exit Meeting
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DETAILS
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1 PLANT STATUS 1.1 Unit 1
At the beginning of the inspection period, Unit I was at 85 percent power at j
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the request of the dispatcher. The unit returned to 100 percent power on i
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April 19.
On April 23, the unit reduced power to 60 percent per the dispatcher's request.
On April 24, the unit reduced power to 20 percent per
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the dispatcher's request and returned to 60 percent power the same day.
On
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April 30, the unit returned to 100 percent power. On May 19, the unit reduced
i power to 85 percent due to a trip of a heater drain pump.
The unit returned t
to 100 percent power on May 20. At the end of the inspection period, the unit
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was at 100 percent power.
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1.2 Unit 2 l
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At the beginning of the inspection period, the unit was at 100 percent power.
l On May 1, the unit began a power decrease at 15 percent per hour for
Steam Generator Inspection Outage 2P-93-01.
The reactor was manually tripped, and the generator output breaker was opened the same day.
On May 16,
following completion of the outage, the unit commenced a power increase and l
reached 100 percent power on May 18. At the end of this inspection period,
the unit was at 100 percent power.
2 OPERATIONAL SAFETY VERIFICATION (71707)
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f 2.1 Unit 2 - Planning for Steam Generator Inspection Outage 2P-93-01 l
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On April 22, the inspector attended a pre-outage briefing provided by the
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licensee. The shutdown operations protection plan was presented.
Six key l
safety functions were identified: maintenance of heat removal, maintenance of
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inventory, maintenance of vital AC, maintenance of vital DC, maintenance of
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reactivity, and containment closure.
Possible alternatives for achieving each safety function were defined. A SCORE card was generated to define the
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minimum equipment availability requirements for various outage periods that corresponded to specific plant operating conditions.
The minimum requirements
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were in excess of Technical Specification requirements and provided additional
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controls to ensure safe shutdown during varicus plant configurations.
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2.2 Unit 2 - Decision Not to Use Nozzle Dams During Steam Generator l
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Inspection Outage 2P-93-01
r The use of steam generator nozzle dams during Outage 2P-93-01 was evaluated i
prior to the start of the outage.
The licensee determined that performance of
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the planned steam generator inspections without the installation of nozzle i
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dams was acceptable.
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t The nozzle dam configuration was analyzed assuming the RCS was initially I
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flooded to a normal level of 40 inches in the pressurizer, the emergency core cooling system vent valves were opened, and the pressurizer manway was
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removed.
The configuration without nozzle dams installed was analyzed l
assuming the RCS was initially flooded to 24 inches above the bottom of the
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hot leg.
No credit for injection flow was taken for either calculation.
i Calculations were performed to estimate time to core uncovery (TTCU) and time l
to boil (TTB) with the following results:
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WITH WITHOUT i
N0ZZLE DAMS N0ZZLE DAMS
(MINUTES)
(MINUTES)
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TTCU 187.2 133.3 l
TTB 32.8 13.1 l
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l Under the listed assumptions, the TTCU and the TTB improved with the
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installation of the nozzle dams.
HowcVer, the licensee concluded that the use
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of nozzle dams during this outage did not provide a significant increase in i
safety margin based on the following:
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The additional water volume obtained by refilling the RCS to some
indicated pressurizer level after installation of the nozzle dams
would not necessarily all be available to prevent core uncovery in
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the event of a loss of shutdown cooling.
l The work scope of the outage did not impact the availability of l
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either train of shutdown cooling.
Further, most prior industry-i 4,
loss-of-shutdown-cooling events occurred while changing levels.
Installation of nozzle dams would have required one additional RCS
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fill and drain evolution.
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Containment integrity would be maintained intact during reduced
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s inventory.
The presence of RCS vent pathways through the steam generator
manways would be expected to preclude any significant
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pressurization of the RCS in the event of a loss of shutdown i
cooling. As a result, gravity feed from the refueling water tank would be available to make up any lost inventory due to boil-off.
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Use of nozzle dams and the pressurizer manway vent path made this i
means of inventory makeup less effective.
The decision to not install nozzle dams was carefully considered and was considered to be reasonable.
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-6-2.3 Unit 2 - P1 ant Shutdown for Steam Generat or Inspect ion Out age 2P-93-01 On April 30, the shift superintendent and the control room supervisor conducted a crew brief covering the preparations for the outage.
The inspector observed the briefing and determined that it was thorough and addressed the highlights of the plant power decrease and abnormal equipment conditions.
The operators were also given a written handout which provided an overview of the major activities which would occur prior to each mode change and "rphasized appropriate precautions.
The need to conduct the shutdown in a methodic al manner without rushing to meet a schedule was stressed.
The inspector was present in the Unit 2 control room and observed the power decreasr that commenced at midnight on May 1.
Additional personnel were present during t he power naneuver to provide support and training assistance.
The shift superintendent maintained good command and control during the evolution.
He clearly assigned responsibilities to the operating crew and the suppnrt personnel.
Ancmalous indications were promptly brought to his attention for disposition.
In preparation for tripping the reactor, the shift superintendent cleared the area behind the operating console to ensure no distraction existed during the standard posttrip actions.
Mode 3 was entered at 2:27 a.m on May 1.
No equipment problems were identified during the performanco of t he st andard posttrip actions and all safety functions were nt 2.4 Unit 2 - Thermal Stratification in Shutdown Cooling Suction Piping During tooldown Te perature instrumentation was installed at the end of Refueling Outage 2R9 to detect thermal stratification on the RCS side of the shutdown cooling s u c t i o n l i rt e.
This instrurentation was installed as a part of the Combustion Engineering Owners Group's efforts to better understand the temperature dif ferent ial s in essentially st agnant 1ines.
On May 5. a condition report was initiated to document the observation that tcp ta boticm t cmperat ure dif f erentials of greater than 34f occurred during the cooldown f or Steam Ger:erator Inspection Outage 2P-93-1.
The licensee determined that an evaluation of the condition would be required prior to heating up the plant.
The icense-believed that the thermal stratification phenomena was caused by renetrat i nn of the hot RCS fluid into the stagnant shutdown cooling line.
While the cause of this phenomena differed from the valve leakage phenomena describe:d in NPC Bulletin 88-03, Thermal Stresses in Piping Connected to t he g Rector Coolant System the resulting thermal stratification was similar.
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< : plot % and planned corrective actions were reviewed against the
require n nts of this bulletin.
ased upon this new information and prior to startup, the licensee performed a e
s t ri < fatigue analjsic on the shutdown cooling piping for a conservative
' vber of f ut ure thermal cycles and concluded that no inrediate safety issue
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Volumetric examinations using enhanced ultra.,onic testing methods had been performed in Refueling Outage 2R8 on critical welds and high stress
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areas.
Dye penetrant surface exams were also performed.
The licensee stated
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that the examinations yielded acceptable results.
The licensee's initial
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response to NRC Bulletin 88-08 stated that this stratification phenomenon did not exist on Unit 2.
As a result of this new information, the licensee
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I planned to submit a revised response to NRC Bulletin 88-08 by July 31, 1993.
2.5 Unit 2 - Reduced Inventory Oversight
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The inspector observed the initiation of draining of the RCS. A handout was
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provided to the operating staff prior to draining which reiterated appropriate.
I precautions and the procedures which would be used during the evolution.
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operator was assigned to continuously monitor the tygon tubing level
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indication during the draining.
After steady state conditions were achieved,
a video display of the tygon tubing was monitored in the main control room.
The installation of the video camera allowed for continuous monitoring of the RCS level without the accumulation of unnecessary dose.
An extra licensed
operator was assigned to the shift during the draining evolution and while the
RCS was in reduced inventory. The extra operator, who was dedicated to
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reduced inventory oversight, recorded the RCS level every 15 minutes and compared the readouts from the alternative level displays.
I 2.6 Unit 2 - Tour of Containment to Ensure Adequate Response to NRC Bulletin 93-02:
" Debris Piuqqing of Emergency Core Cooling Suction
Strainers"
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NRC Bulletin 93-02, issued on May 11, requested the licensee to identify fibrous air filters, or other sources of temporary fibrous material not
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designed to withstand a loss of cooling accident, which were installed or stored in the reactor building.
Procedure 2102.001, " Plant Preheatup and Precritical Check," required that a visual inspection of the reactor building be performed to ensure all trash and unneeded equipment and supplies were removed from the building.
The procedure also required that items to be left in the reactor building permanently would
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be reviewed by engineering.
The potential for sump suction strainer blockage that could cause net positive suction head problems for emergency core cooling pumps was one of the criteria for the engineering review.
Engineering also provided instructions for securing items which were determined to be acceptable to remain in containment.
The inspectors independently toured the reactor building just prior to
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closecut to verify that the Bulletin's requirements were addressed. They interviewed licensee personnel performing and directing the reactor builoing closecut and determined that they were aware of the requirements of the
bulletin.
The actual emergency core cooling sump suction piping was not inspected because the locked grating was not opened during this outage.
Documentation existed which indicated that both euergency core cooling sump c
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suction lines were inspected and determined to be clear of debris following
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the most recent outage, Refueling Outage 2R-9.
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Engineering personnel that were interviewed regarding the basis for the loss
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of coolant accident analysis, stated that all permanently installed insulation met the loss of coolant accident design criteria. A portion of the insulation t
was expected to migrate to the sump following a loss of coolant accident but _
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be acceptable.
t 2.7 Unit 2 - Heat Up Restraints
l The heat up restraint list was reviewed by the inspector on May 8 and 13.
Known safety issues requiring resolution prior to start up were listed.
All
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issues were resolved appropriately prior to startup.
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2.8 Unit 2 - Observation of Control Room Activities During Approach to Criticality
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The inspector observed the approach to criticality performed May 16.
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Procedure 2102.016, " Reactor Startup," provides instructions to take the plant
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from Hot Standby (Mode 3) to Startup (Mode 2).
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Two dedicated licensed operators were assigned to perform the startup
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activities. One was an extra senior reactor operator (SRO) who supervised the
startup, and the other was an extra control board reactor operator who
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performed the reactor startup.
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The extra SR0 performed a very good crew brief which covered the appropriate
material. Access to the control room was strictly controlled by the shift l
l superintendent.
The ascent to criticality went well.
The SRO stopped the ascent after the
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first withdrawal step when he noted that Channel A of the excore log power i
nuclear instrumentation (NI) was not responding to control element j
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assembly (CEA) movement and when it appeared that CEA 42 was slipping.
The
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SR0 checked the Technical Specifications and verified that the withdrawal
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could continue with the remaining three NI channels operable, and he had
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instrumentation and control (I&C) personnel monitor the problem CEA.
He also j
determined that NI Channel A was operable between the ranges of 1 percent to
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100 percent of full power. The SR0 performed another crew brief on the i
situation before continuing. The licensee continued to troubleshoot the problem with NI Channel A and the problem with the CEA.
Since the CEA was at it's upper stop position (fully withdrawn), further checks on this CEA will be conducted during the next plant outage.
Stopping CEA withdrawal to verify the Technical Specification, dispatching I&C personnel to monitor the problem CEA, and the crew brief were seen as a strength.
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2.9 Unit 1 - Trip of Feedwater Heater Drain Pump P-8B
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A condition report was initiated on May 19 as the result of damage to a pressure switch caused by improper stacking of self-contained breathing j
apparatuses dur;ng a monthly inspection. A health physics technician stacked l
the self-contained breathing apparatus cases next to a handrail and then,
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inadvertently, knocked a case over the edge.
The case fell on Pressure l
Switch PS-3038, which senses pressure in the moisture separator reheater drain i
tank, and damaged the switch. This caused Feedwater Heater Drain Pump P-8B to
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trip.
Operators reduced plant power to 85 percent to bring the moisture
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separator reheater drain tank flow within the capacity of the high level dump
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line to the condenser.
The plant continued to operate at 85 percent power
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until the pressure switch was replaced.
The licensee's operability j
determination of the effect of the damaged pressure switch on plant operation
was reviewed by the inspector and was considered to be acceptable.
l 2.10 Unit 1 - Self Verification i
The stop, think, act, and review self-check program was implemented for Unit l
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The program had already been implemented for Unit 2.
It was simpler and
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easier to use than the previous seven-step program. The licensee uses a human i
performance evaluation system program to identify the true root cause of i
significant problems caused by personnel error.
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The changeover to the stop, think, act, and review system for both units was-
considered to be an improvement in the licensee's self-assessment program.
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2.11 Units 1 and 2 - Monitoring For Equipment Degradation The inspector observed the licensee's gathering of equipment performance data which was used to ascertain equipment degradation.
Plant personnel routinely gathered equipment performance information without formal instructions for this data collection.
For example, Unit 1 personnel trended Emergency Feedwater Pump P-7A speed and control signal voltage to monitor governor valve performance.
The instrumentation bookups were controlled by a job order (J0)
and the pump operation was controlled by Procedure 1106.06, Supplement 2,
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" Steam Driven Emergency Feedwater Pump (P-7A) Test (Monthly)." Similarly,
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Unit 2 personnel collected low pressure safety injection (LPSI) pump performance data without formal instructions addressing the data collection.
The pump was operated in accordance with Procedure 2104.004, " Shutdown Cooling System," and the crew was briefed regarding pump operating limits which were i
taken from Procedure 2104.040, Supplement 8A, "LPSI System Operation."
Both the Unit I emergency feedwater pump and the Unit 2 LPSI pump remained operable throughout the evolutions. The inspector determined that all critical activities were controlled by plant procedures and that the test data was not being relied upon to demonstrate operability.
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2.12 Units 1 and 2 - Oversight of Contractors
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The licensee formed a task force and performed an assessment of maintenance
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work practices performed by contractors over the past 3 years. The. task force-
-l determined that procedures and training in this area have improved
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significantly over the past 3 years.
The inspector reviewed the licensee's assessment and performed an independent
check of the data to ensure that the licensee's conclusions were based on
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appropriate inputs. Two 1992 condition reports were identified that were not
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included in the licensee's base condition report list.
Interviews with the licensee indicated that they were cause-coded to be communication or l
supervision problems as opposed to maintenance practice problems. The
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inspector concluded that, while a different sampling of the condition report
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data base would have provided a more comprehensive review of contractor management, the portion that was reviewed was a fair sample.
Based on a i
review of information from the condition reporting system, control of contractors has improved steadily since 1990.
The improving trend was l
determined to be valid.
t The inspector reviewed a sample of prior contractor control condition reports
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and noted no common root causes for prior contractor control problems.
Specific condition reports documented comprehensive corrective actions for each identified discrepancy. The inspector also noted that the condition.
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reporting system appeared to be efficiently utilized to document identified
deficiencies and to effect comprehensive corrective actions.
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The overall self-assessment was determined to be fair and valid.
2.13 Unit 2 - Mock-Up Training in Preparation for Steam Generator Tube
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Inspection
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in an effort to reduce personnel exposure during the steam generator tube
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inspection, the health physics department conducted training on a mock-up for
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contractors associated with the inspection.
The training, which was targeted at the contractors responsible for installing equipment in the steam generator bowls, included time trials of each individual for entering and exiting the steam generator bowl mock-up.
The health physics instructor was questioned regarding the licensee's expectations of the contractors.
The instructor l
stated that the contractors were to minimize the amount of time spent entering
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and exiting the mock-up in order to practice reducing the amount of exposure.
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that may be received while performing the actual task. The workers who did not meet the minimum time requirements were not eligible to perform the actual task.
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2.14 Unit 2 - Technical Specification for Main Steam Safety Valves
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An issue was identified as an unresolved item in NRC Inspection Report 50-245/92-13; 50-336/92-14; and 50-423/92-13 for the Millstone plant, I
which concerned Millstone Unit 2's interpretation of Technical l
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Specification 3.7.1.1.
Millstone Unit 2 Technical Specification 3.7.1.1 was l
applicable in operating Modes 1 through 3 ar.d required that, with one or more main steam line code safety valve inoperable, the licensee must either restore
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the safety valve to operable status or reduce the high power level. trip
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setpoints within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Otherwise, the. facility must be placed in at least t
~ hot standby (Mode 3) within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown (Mode 5)
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within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Millstone's interpretation was that the shutdown requirements of Technical Specification 3.7.1.1 ceased to apply when
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the unit was in Mode 4.
Based on the fact that ANO, Unit 2, Technical Specification 3.7.1.1.is.similar to Millstone Unit 2, the inspectors conducted a review to determine AN0's interpretation of this Technical Specification.
The licensee's station logs taken during the power reduction performed to enter Refueling Outage 2R9 were reviewed for main steam safety-valve setpoint t
testing to determine if the requirements for Technical Specification 3.7.1.1
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were met. All Technical Specificatior requirements were met. The actual l
performance of the main steam safety valve setpoint testing was previously
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witnessed and documented in NRC Inspection Report 50-313/92-11; 50-368/92-11.
The inspector questioned the licensee to determine their understanding of Technical Specification 3.7.1.1.
Based upon this discussion, the inspector determined that the licensee's approach to this Technical Specification was
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consistent with the requirements.
2.15 Units 1 and 2 - System Piping and Instrument Drawings and Remote
Shutdown Procedure Audit A walkdown and audit was performed for safety system piping and instrument
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drawings located and displayed in the auxiliary building to ensure that the
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latest revision was displayed.
All drawings were the latest revision and no
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problems were identified.
j An audit was also performed of Unit 2 Procedure 2203.030, Revision 4, " Remote l
Shutdown," and Unit 1 Procedure 1203.029, Revision 4, Procedure Change 1, i
" Remote Shutdown," to ensure that the procedures were in their proper
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locations and that the latest revision was utilized.
No problems were identified.
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In addition, emergency operation procedures located in the Technical Support Center were also verified to be the most current revisions.
t 2.16 Unit 1 - Reactor Building Spray System Walkdown A walkdown of the reactor building spray system was performed to verify proper alignment of major flow path valves.
Piping and Instrumentation Diagram M-233, Revision 63, " Chemical Addition System"; M-232, Revision 75, Sheet 1, " Decay Heat Removal System"; and M-236, Revision 77, " Reactor Building Spray Core flood Systems," were used as guides for valve alignment.
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l All valves located outside of the reactor building were identified and i
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l appeared aligned per the diagram. No problems were identified.
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2.17 Conclusions The continued implementation of the SCORE card program during the planning and
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performance of Steam Generator Inspection Outage 2P-93-01 was viewed as a strength.
The choice not to use nozzle dams during the Unit 2 outage was j
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carefully considered by the licensee and appeared reasonable. The prebriefing.
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and oversight provided the operating crew associated with the Unit 2 plant shutdown were viewed as a strength. Oversight of the RCS during draining and i
reduced inventory was excellent, r
The licensee's program for preventing debris from clogging the suction of the containment recirculation piping was consistent with their design assumptions
and was well implemented.
l Heatup restraint evaluations were determined to be appropriate.
The use of informal methods to gather information regarding potential equipment
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degradations was determined to be acceptable because the equipment operation
i was conducted within the bounds of approved instructions and the data was not being used to demonstrate operability.
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Based on a review of information from the condition reporting system, control of contractors has improved since 1990.
l The licensee adequately communicated their expectations during mockup training
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i in preparation for the steam generator tube inspection and the training session was considered excellent.
All posted safety system piping and instrument drawings were of the latest
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revision.
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3 ENGINEERED SAFETY FEATURE SYSTEM WALKDOWN (71710)
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3.1 Unit 1 - Sodium Hydroxide Walkdown i
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A walkdown of the sodium hydroxide system was performed to verify valve
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i alignment.
Piping and Instrumentation Diagram M-233, Revision 63, " Chemical Addition System," was used as a guide for valve alignment.
All valves were identified and aligned per the diagram. A sodium hydroxide buildup was noted
on Sodium Hydroxide Tank Isolation Valve CA-49 and Discharge Valve CV-1616.
A
deficiency tag dated February 25, 1993, referencing JR 781710, was also noted l
on Valve CA-49.
The deficiency tag indicated that Valve CA-49 needed to be j
repacked.
The date of initiation listed on JR 781710 was June 2, 1987.
'
The inspector's investigation indicated that JO 00735100 was also written on June 2,1987, to repair the packing leak on Valve CA-49.
However, JO 00735100
was never performed and was still open.
The inspector questioned the licensee
!
concerning the work prioritization of JO 00735100 and the effect of corrosion
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The licensee indicated that J0 00735100 was not worked due to the fact that Valve CA-49 was
operable, the leak was minor, and they were considering replacing the existing sodium hydroxide system.
The licensee stated that the accumulation of sodium hydroxide on Valve CA-49 would have no adverse effect based on the fact that
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the system was at ambient temperature.
Further review of the work
prioritization of JO 00735100 and the effect of the accumulation of sodium i
hydroxide on Valve CA-49 is planned. This review will be tracked as
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Inspection Followup Item 313/9305-01.
4 MONTHLY MAINTENANCE OBSERVATION (62703)
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4.1 Unit 2 - Temporary Modification of the Control Element Drive I
Mechanism Cooling System (JO 00892247)
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On May 4, resistance temperature detectors (RTD) were installed in the control element drive mechanism cooling system in an effort to determine the root cause for failures of the CEA reed switch position transmitters (RSPT).
The RTDs will be utilized to trend temperature data to determine if adjustments in
the cooling system, which aids in maintaining RSPT temperature, were required
~
to preclude possible overheating of the transmitters.
.
The detectors were installed under Temporary Modification 93-2-004.
Overall,
the installation of the RTDs, as observed by the inspector, was well planned
!
and was executed smoothly.
However, the inspector also noted that two
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I technicians used the 3/4-inch reactor vessel head vent piping as a structural member to secure their safety harnesses for fall prevention even though
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alternate, stronger, structural members to secure the safety lines were
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available in the area. This observation was discussed with licensee
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personnel. As a result of this discussion, the licensee performed a calculation and determined that the resultant stresses were below the l
operability limits for static loading conditions of this piping.
For dynamic
loads, however, stresses projected by elastic calculation methods may have l
been sufficient to cause pipe failure. The licensee believed that a more
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rigorous analysis technique would demonstrate that failure would not occur
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even for dynamic loading.
Securing safety lines to the head vent pipe was considered to be a weakness.
4.2 Pressurizer Safety Valve 2PSV-4634 Replacement (JO 00887843)
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The licensee has been proactive since 1989 in minimizing pressurizer relief valve leakages by installing relief valves with flexidiscs. These valves were supposed to provide an enhanced leak tight seating surface.
However,
continued leakage of the modified relief valves, which was an industry-wide
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occurrence, prompted the licensee to modify all of the spare relief valve seats to allow a more flexible seating surface.
On May 4,1993, Pressurizer Safety Relief Valve 2PSV-4634 was removed in
accordance with Procedure 2402.131, Revision 2, " Removal of the Unit 2 Pressurizer Code Relief Valves 2PSV-4633 & 2PSV-4634." The valve was shipped
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-14-to the vendor for modification. The valve was replaced with a modified spare valve and was installed in accordance with the applicable steps of Procedure 2402.132, Revision 3, " Installation of the thiit 2 Pressurizer Code
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Relief Valves 2PSV-4633 & 2PSV-4634." The workers were knowledgeable of the i
task and maintained foreign material control in accordance with the procedure.
Quality Assurance verified foreign material exclusion and confirmed quality control hold points.
.
Additional leak trending indicated that the modified valves were currently maintaining leak tightness.
4.3 Unit 2 - Temporary Modification to Service Water Pump 2P-4A Temporary Modification 93-2-008 was initiated to install nonqualified power
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cables for Service Water Pump 2P-4A due to a failure of the permanent cable.
The temporary modification installed temporary, unqualified power cable in lieu of qualified power cable due to the unavailability of qualified cable.
Since the pump did not have qualified power cable, the licensee declared the i
pump inoperable even though the unqualified cable allowed the pump to operate, To compensate for the loss of Pump 2P-4A, swing Service Water Pump 2P-4B was
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realigned in place of Pump 2P-4A.
Since Pump 2P-4A was designed to be i
sequenced onto it's bus before Pump 2P-4B, under a loss of offsite power condition which caused the bus to be powered with an emergency diesel
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generator, the modification package included lifting a wire to modify the l
control circuitry for Pump. 2P-4A.
The postmodification testing package
,
included documentation and independent verification of the lif ted wire but did r
not provide for testing of the control circuit modification.
Based'upon
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eview of this modification package, the inspector determined that I
postmaintenance testing activities were appropriate for this temporary modification.
4.4 Unit 1 - Valve Operating and Test Evaluation System (V0TES) of Low Pressure Injection Block Valve CV-1400 (JO 00876611)
On May 24, V0TES was used to test the motor operator of Low Pressure Injection Block Valve CV-1400 in accordance with Procedure 1403.040, Revision 6, " Unit I and Unit 2 Motor Operator Valve (MOV) Testing and Maintenance of Limitorque SMB-0 thru 4 Actuators." The test results indicated that the design maximum total thrust was exceeded when the valve was closed.
An operability determination was performed and concluded that the maximum thrust was below
'
the allowable loading for the valve stem, which was the weakest member Based upon this determination, the "as-left" thrust condition for the valve was considered to be acceptable.
No other discrepancies were identified during the VOTES testing.
4.5 Laser Alignment for Rotatina Eauipment A new laser method for rotating equipment alignment was being utilized on various components. The licensee indicated that the laser alignment method would save a significant amount of time as well as radiation dose exposure
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compared to the previous reverse dial alignment method. The licensee indicated that although the laser alignment equipment was not listed on the
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current measuring and testing equipment list for calibration, vibration i
analysis performed during postmaintenance testing of equipment would be_used l
to confirm the accuracy of the laser alignment equipment since the vibration ~
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analysis equipment was listed on the measuring and testing equipment list for
calibration.
Training for the new laser method of rotating equipment-
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alignment was beino provided to technical and maintenance personnel.
The licensee's approach to invest in new technology, thereby reducing i
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radiation dose exposure, was considered a strength.
4.6 Conclusions
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The licensee's maintenance activities appeared to be appropriate.
The
'
reliance on headvent piping to support personnel in the event of a fall was considered to be a weakness. The licensee's decision to install a temporary
,
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power cable so that Unit 2 Service Water Pump 2P-4A would remain capable of operation was viewed as a strength because it provided for additional service
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water capacity. Another strength was the licensee's purchase of new maintenance technology so that personnel radiation dose exposure would be
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reduced.
5 BIMONTHLY SURVEILLANCE OBSERVATION (61726)
5.1 Unit 1 - Turbine Driven Emergenc_y Feedwater Pump P-7A Surveillance
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Testing (JO 0892053)
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On April 20, the inspector observed portions of the testing being performed in accordance with Procedure 1106.06, Supplement 2, Revision 47, Permanent Change 2, " Steam Driven Emergency Feedwater Pump (P-7A) Test (Monthly)." No l
problems were identified.
5.2 Unit 1 - Fire Protection System Surveillance Test of Pump P-6A (JO 00892403)
,
On April 29, the inspector observed portions of the performance of Supplement 2 to Procedure 1104.032, Revision 39, Permanent Change 1, " Fire
Protection System." This procedure was used to test the diesel-driven fire pump. During the testing, a minor lubricating oil leak was observed.
The l
testing was stopped so that the leak could be evaluated by the mechanics. The leak was determined to be minor and a job request was written.
Following the
,
L evaluation, applicable portions of the test were reperformed and correctly documented.
The auxiliary operator communicated frequently with the control room and appropriately handled anomalies, such as an actual start of the motor-driven fire pump. He demonstrated a good grasp of the test objectives as well as system knowledge.
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On May 8, the inspector observed the start of the LLRT for Penetration 2V2 i
performed in accordance with Procedure 2304.197, " Containment Purge System 2V1 and 2V2 Leak Rate Test." The inspector noted that the radiation safety evaluation, which was used to specify the radiation protection requirements for the testing, did not consider the volume of the purge system downstream of the penetration.
The inspector also noted that the limits specified in the
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controlling radiation work permit were sufficiently conservative such that any
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releases that occurred as the result of the testing would not exceed release
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limits.
As the result of the inspector's observations, the licensee initiated Radiological Information Report 93-046 to document the inappropriate
!
radiological safety evaluation.
Radiological Safety Evaluation Request 93-016 was initiated to provide a corrected evaluation for future performances of this testing. The LLRT was successfully completed on May 9.
5.4 Unit 1 - Power Range Linear Amplifier Calibration (JO 00892903)
j I
On May 5, the inspector observed the performance of Procedure 1304.032, Revisior.10, " Unit 1 Power Rtnge Linear Amp Calibration at Power." A printout of the power data was obtained from the plant computer and was reviewed by the technician.
The tolerances for total power error and offset power error, listed in the procedure for reactor power greater than 40 percent, were f
satisfied.
No power range adjustments were required and the remainder of the procedure was marked "Not Applicable."
5.5 Conclusions Personnel demonstrated a clear understanding of testing and test requirements.
The radiation work permit (RWP) associated with the Unit 2 local leak rate of-Penetration 2V2 was not rigorously developed, however, the end result of the i
imposed radiation work practice controls was acceptable.
6 0CCUPATIONAL RADIATION EXPOSURE (83750)
The licensee's program was inspected to determine compliance with
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Unit 1 Technical Specifications 6.3, 6.8, 5.10, and 6.11; Unit 2 Technical
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Specifications 6.3, 6.8, 6.11, and 6.13; the requirements of 10 CFR Part 20; l
and agreement with the commitments of Chapter 11 and 12 of the Safety Analysis Reports for Ur.it 1 and 2, respectively.
6.1 Organization and Management Controls
{
There had been only minor changes to the radiation protection organization since it was reviewed in NRC Inspection Report 50-313/92-04; 50-368/92-04.
A few of the changes included the realignment of the decontamination group to
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fall under the Health Physics Operations section and the formation of a Health Physics Specialist section.
These changes were an improvement and did not
adversely affect the radiation protection program.
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The Radiation Protection department had instituted the concept of zone
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coverage for the radiologically controlled area (RCA) since the last NRC inspection of this area.
The concept provides for accountability and ownership of an area by radiation protection technicians who are assigned a zone in the RCA for which they have responsibility.
The Radiation Protection Manager indicated that there were a few startup problems associated with.the zone coverage concept, but that the program was effective. The zone coverage raised the radiation protection technician's awareness and concern for
activities occurring in their zone.
The licensee had purchased new alpha counters and two standup whole body
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counters. The whole body counters were acquired to be used for special scans The licensee plans to have them operational for the upcoming Unit 1 outage in September. Other planned changes in equipment and facilities include a new computer system for radiological information and the combining of the entrance
!
and exit for the RCA into a common area.
Discussions with the Radiation Protection Manager indicated that management support for the Radiation Protection program was very good. Through observations and discussions with per.connel, it was determined that the
Radiation Protection department had a good working relationship with other
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departments.
The level of staffing for the radiation protection program was
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maintained at a sufficient level.
Day to day oversight of the radiation protection program was very good.
Radiation Protection supervisors spent an appropriate amount of time in the
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RCA to keep abreast of activities that.were performed.
delected audits and surveillances of the radiation protection program were reviewed back to October 1, 1991.
The audits'and surveillances were comprehensive and included a person with technical expertise on the audit teams, and the responses to findings were adequate and timely.
The audit and surveillance program in this area was excellent and identified appropriate findings, recommendations, and observations.
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Selected radiological information reports were reviewed. The reports.were adequate to identify and correct problems.
Problems that were significant to
the Radiation Protection department were appropriately elevated and included l
in tne licensee's condition report system.
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6.2 Training and Qualifications of Personnel A review was performed of the licensee's radiation worker training and general employee training programs.
The inspector attended a requalification class for site access training (GET-1), radiation worker training (GET-2), and
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respiratory protection training (GET-3). The requalification training had been revised such that it only covered major changes that had occurred. The workers were tested and, if they failed, they were required to take a more
comprehensive training class. The practical factors training was observed and determined to be good.
The licensee's general employee training and radiation
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worker training satisfied the requirements of 10 CFR Section 19.12, and the guidance in Regulatory Guides 8.13, 8.27, and 8.29.
The ir-pector reviewed the licensee's training program for radiation
'
protection technicians.
Selected radiation protection technician training i
lesson plans were reviewed. The lesson plans were good and adequately covered the subjects. Recent industry events and changes in procedures were appropriately incorporated in the lesson plans.
It was determined that the licensee's training program was being implemented in accordance with station
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procedures.
,
Discussions with licensee representatives indicated that the selection of s
contract radiation protection technicians required successful completion of a
comprehensive written screening examination.
The contractor technician would also attend formal training, as necessary, for site specific radiation protection, respiratory protection, emergency planning, and station
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procedures.
Selected training records of radiation protection technicians were reviewed to determine if required training had been performed. The review indicated that
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ihe individuals had received the appropriate training.
Qualifications of the radiation protection training instructors vere reviewed and found to be good.
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The licensee had made courses available at the site for persons interested in pursuing registration with the National Registry of-Radiation Protection Technologists (NRRPT).
There were approximately 14 individuals in the
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raciatinn protection program, one in the inhouse events and. analysis program,
!
and one in the training department who were registered with NRRPT.
6.3 External Exposure Control i
The licensee's external exposure control program consisted of whole body monitoring, direct radiation surveys, RWPs, and administrative exposure limits.
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The inspector noted that the licensee obtained individuals' previous exposure
histories, verified completion of radiation worker training, and had performed an incoming whole body count prior to issuing dosimetry.
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The licensee had received accreditation from the National Voluntary Laboratory
Accreditation Program in all categories.
The accreditation is valid until
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i January 1, 1994.
The dosimetry processing area and the licensee's quality assurance techniques were reviewed and determined to be adequate.
The licensee had also conducted a quarterly quality assurance verification with the assistance of a vendor.
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Records of the calibration of self-reading dosimeters (SRDs) were reviewed and
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indicated that the SRDs were calibrated at the proper frequency. The licensee i
had a program to review discrepancies between exposures obtained from SRDs and
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i thermoluminescent dosimeters (TLDs).
The inspector reviewed the discrepancy records and determined that the differences in exposures were adequately i
evaluated.
,
The licensee had adequate procedures to address the loss of a TLD or SRD and l
an offscale SRD.
The inspector reviewed selected records of individual:. who
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had lost their TLD or had their SRD go offscale and determined that the appropriate actions were taken to determine the individual's exposure.
l l
The inspector observed personnel entering the RCA and noted that they were l
wearina their TLDs and SRDs The licensee had placed additional reminders and
!
a barrier to ensure personnel had the proper dosimetry prior to entering the RCA.
Additional dosimeter devices, such as high range SRDs, multipack TLDs,
'
alarming dosimetry, and telemetric dosimetry were issued when required for select work evolutions, such as the recently completed Unit 2 steam generator l
work.
i The inspector reviewed a selected sampiing of RWPs issued for the Unit 2 steam i
generator outage. The RWPs incorporated sufficient radiological controls.
[
The inspector attended three prejob briefings. The briefings were effective I
and covered appropriate topics.
Selected RWPs that required prejob briefings
!
were reviewed to determine if all individuals listed on the RWP attended a prejob briefing. The review indicated that all individuals that entered the i
RCA on an RWP that required a prejob briefing had attended the required prejob
'
briefing.
On April 27 an unposted and unguarded locked high radiation area (LHRA)
!
condition existed for approximately 15-45 minutes in the trainbay of the
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turbine building.
The condition was identified by a quality assurance
!
inspector who had been observing the resin processing evolution in the
trainbay.
Upon discovery, the licensee documented the condition with a l
radiological information report and with Condition Report C-93-0053.
The l
incident was viewed by the licensee as significant, and a Correctivt Ntions
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Review Board meeting was held to review the causes of the incident and the corrective actions for the incident.
The inspector reviewed the condition j
report and attended the Corrective Actions Review Board meeting.
!
The incident occurred during work activities associated with a Unit 2 resin l
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t>ansfer.
The resin had been transferred to a liner in the trainbay and
'
cewatering of the resins had been completed on April 23. On April 27, the
!
workers were to disassemble the resin transfer equipment and move the liner to
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the radwaste storage building.
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The removal and storage of the fillhead required three individuals to be dressed in a single set of anticontamination clothing, plastic coveralls, and respirators.
The most experienced radiation protection technician covering
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the job and the radwaste vendor worked on top of the liner to remove the i
temporary shielding, glovebag, and fillhead. The other dressed-out individual
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i contaminated area. Two individuals worked outside of the area, one was the crane operator and the other was a radiation protection technician that
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maintained radiological controls in the ceneral area. The work evolution was.
l also observed by a quality assurance inspector.
,
After the temporary lead shielding, glove bag, and fillhead were removed, a
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survey was performed that indicated exposure rates of 20 R/hr on contact with
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the resin and 12 R/hr at I foot. Therefore, the area on. top of the liner had
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met the licensee's criteria for an LHRA, which is an accessible area with exposure rates greater than or equal to 1000 mR/hr measured at I foot from the
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source of radiation. After the fillhead was removed and stored and the i
individuals had exited the contaminated area, the radwaste vendor and the
.i radiation protection technician began exhibiting signs of heat stress. They i
continued to provide support to release the crane from the area. -The two affected individuals went to the plant services locker room to get some water i
and cool down. The radiation protection technician who was covering the outside area left the area to count cir samples and the quality assurance inspector left the area to review records at Controlled Access (CA) Area'2.
When the inside radiation protection technician felt his physical condition and that of the radwaste vendors deteriorating, he had the laundry technician call the Unit 1 control room to have the emergency medical team dispatched to
'
the trainbay for assistance.
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The affected individuals were treated for heat stress and instructed to go to the radwaste building to rehydrate and res+
P'e outside radiation protection technician and the quality assurance insp
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turned to the trainbay.when
they heard the page for the emergency medi :1 te They noted that the
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individuals were being attended to and retui, the;r respective. tasks.
After the individuals were treated for heat stre, and left to go to the radwaste building, all the other personnel left t e trainbay.
The quality assurance inspector had finished his work at CA Area 2 and had l
returned to his office.
Later, the quality assurance inspector was returning
to CA Area 2 by way of the trainbay and noted there was no activity in the i
trainbay.
He was concerned about the exposure rates on top of the liner and
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noted that there was no lead shielding visible on top of the liner and that i
the liner was unguarded. He reported his concern to the Health Physics-
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Superintendent, who sent radiation protection technicians to survey and guard the liner.
The top of the liner was later shielded to reduce the exposure rate to less than 500 mR/hr at 1 foot.
In conjunction with the review of the incident by the individuals tasked by the condition report, a human performance enhancement system evaluation was performed.
Together, both reviews of the incident captured the causes of the
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incident.
Some of the causes were as follows:
The responsible supervisor / temporary foreman was not at the job site
during the fillhead removal.
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The supervisor had not discussed priorities of assigned tasks for the
temporary foreman.
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The prejob briefing failed to discuss in sufficient detail specific
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expectations and contingencies for heat stress.
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An insufficient number of individuals experienced with this activity
were assigned to the work activity.
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The most experienced radiation protection technician assigned to the
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activity was involved in multiple tasks in addition to adiological
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controls.
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The medical emergency involved the most experienced individual', who was i
the most knowledgeable of the radiological conditions at the job site.
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t The licensee performed numerous immediate corrective actions including:
Immediately dispatching a radiation protection technician to survey and
guard the area.
Shielding the top of the liner to reduce the exposure rate to less than i
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1000 mR/hr at I foot.
i Disciplining the individuals involved.
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Reviewing access control records and exposure reports to ensure no
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unusual exposures were attributed to this event.
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Obtaining a temporary shield plate to place over the liner opening
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immediately after the fillhead was removed.
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Issuing a memo to the radiation protection personnel describing the i
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event and conveying management's expectations on performance standards-l and accountability.
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The licensee committed to have the following long-term corrective actions to i
prevent recurrence in place by November 30, 1993.
j Provide expectations for supervisory staff and-temporary foremen on i
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performance of.their jobs.
Implement a self-verification program for radiation protection
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employees.
i Review the event with all radiation protection personnel and place i
emphasis on effective prejob briefings, acceptable limitations for
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transient radioactive materials, clarification that multiple tasks that i
t prevent complete and positive r-diological controls will not be engaged,
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changing conditions, and posting expectations for anticipated worse case l
conditions.
Determine if emergency planning procedures should include a prompt for
individuals to ensure plant conditions or job site activities are stable.
Revise certain procedures to include a caution statement that the l
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removal of the temporary shielding and fillhead may result in an LHRA
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condition, a statement that stipulates a supervisor / temporary foreman
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and adequate staffing shall be at the job site-during resin transfer and
fillhead removal activities when anticipated exposure rates are greater
,
than 1 R/hr at 1 foot, and include detailed job coverage expectations
for controlling radioactive materials with exposure rates greater than.
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1 R/hr outside of controlled access.
Review the conduct of infrequently performed tasks or evolutions
!
as it applies to complex radiation protection activities and
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management oversight.
I Have limited staff meetings with the Health Physics Superintendent
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l and/or Radiation Protection Manager regarding attention to detail,
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problems with the radiation protection program, and responsibility I
and accountability.
I
Initiate an independent assessment team to review findings and_ANO l
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implemented corrective action; after actions are completed and to review issues such as management oversight, supervisory involvement, and attention to detail.
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Units 1 and 2 Technical Specification 6.8.1.a. requires, in part, that written procedures be established, implemented, and maintained covering the applicable
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procedures recommended in Appendix A of Regulatory Guide 1.33 which, in turn,
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recommends access control to radiation areas be covered by procedures.
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Section 6.1.5 of Procedure 1012.017, " Radiological Posting and Entry / Exit Requirements," Revision 0, states that all acct,ible areas with exposure
.
rates greater than or equal to 1000 mR/hr measured at 1 foot from the source
!
of radiation or any surface penetrated by the radiation, LHRAs, shall be
locked or guarded at all times. Also, Section 6.6.2.8 of Procedure 1012.017
indicates that the posting requirements for an LHRA outside the controlled'
access area require the area be posted " Locked High Radiation Area." The i
,
failure to have an LHRA locked or guarded at all times or to have an LHRA i
posted as a " Locked High Radiation Area" are viewed together as a violation of Technical Specification 6.8.1.a.
This violation will not be cited because the r
licensee's efforts in identifying and correcting the violation meet the
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E criteria for enforcement discretion specified in Section VII.B 2 of Appendix C i
to 10 CFR Part 2.
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6.4 Internal Exposure Control The inspector observed the operation of the two bed-type whole body counters.
i The licensee requires all incoming and exiting personnel to be whole body
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counted prior to entry into the RCA and upon termination of work at ANO.
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Whole body counts were performed on individuals that exhibited facial
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contamination around the nose or mouth and on individuals that exceeded
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administrative limits for maximum permissible concentration hours (MPC-hrs).
During tours of the Unit 2 containment, the inspector noted that the licenseo
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used portable ventilation units with high efficiency particulate filters,
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where practical, as a means of reducing airborne contamination.
The inspector l
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also noted that the licensee had an adequate amount of calibrated continuous
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air monitors for the auxiliary building and the reactor building.
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The inspector observed air samples being taken and noted that they were j
representative of the workers' breathing zone. The licensee had an
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appropriate method which used the air sample data to track MPC-hrs for j
individuals.
l Respirator fit testing was observed by the inspector and determined to be l
adequate.
Respirators were issued from the radiation protection desk at the I
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entrance to the RCA. On May 24, the inspector reviewed records of respirator issue and noted individuals that had received respirators were qualified and had received respirators of the proper size and type. A cross-check of the
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respirator issue log and the respirator inspection / maintenance log identified that two respirators had been issued that were past their 30-day inspection and operational check period.
In particular, Respirator S-16 that was issued
,
and worn on May 7 had been last inspected April 5, and Respirator M-ll4 that l
was issued and worn on May 6 had no record indicating that it had been'
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inspected.
t The licensee subsequently informed the inspector that their Quality' Assurance l
department had recently performed a surveillance of respiratory protection j
activities.
They provided the inspector with draft Quality Assurance Surveillance Report 93-017, " Respiratory Protection Activities,-" which had been performed during the period May 4-24.
The surveillance indicated that the auditor had identified the problem of the issuance of respirators past the 30-day inspection date prior to the time the inspector identified the problem.
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Due to the low frequency of occurrence of the problem, the auditor indicated l
his concern as a recommendation with a response required by June 27.
i As part of the licensee's initial corrective actions, they reviewed j
378 respirators that were ready for issue and noted that 6 did not have proper
inspection documentation, so they removed them from service.
They then i
reviewed the 260 respirators that were issued in May and noted that 28 were
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not properly documented.
At a meeting with the licensee's representatives, additional corrective
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actions were presented. The corrective actions included testing the-i
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respirators in question, performing an inventory of all respirators, and l
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delegating a Health Physics supervisor to perform a complete overview of the
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respiratory protection program, including a review of the qualifications of
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respirator users. The licensee also committed to develop a computer program
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to control the issuance of respirators.
This program would provide an
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integrated system containing respirator inspection data and verify training i
and qualifications of the respirator user prior to issue.
Units 1 and 2 Technical Specification 6.8.1.a. requires, in part, that written procedures be established, implemented, and maintained covering the applicable i
procedures recommended in Appendix A of Regulatory Guide 1.33 which, in turn, j
recommends respiratory protection be covered by procedures.
Section 6.1.1 of
Procedure 1601.600, " Issue, Use, and Return of Respiratory Protection
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Equipment," Revision 0, states that all respiratory protection equipment is i
required to have been inspected and operationally checked at least 30 days
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prior to its use.
The failure to inspect and operationally check all
respiratory protection equipment at least 30 days prior to use is a violation
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of Technical Specification 6.8.1.a.
This violation will not be cited because
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the licensee's efforts in identifying and correcting the violation met the
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criteria for enforcement discretion specified in Section Vll.B.2 of Appendix C
to 10 CFR Part 2.
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6.5 Control of Radioactive Materials and Contamination, Surve_ys, and
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Monitoring j
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The inspector reviewed selected. survey records and determined that the j
licensee had implemented a good radiation area survey program.
Survey results
were documented properly.
Independent surveys performed by the inspector were i
in good agreement with surveys performed by the licensee.
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i During tours of the RCA, the inspector noted that housekeeping was effective.
Radiation protection technicians provided good coverage of work activities.
Observations and discussions with personnel indicated that there was good i
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conperation between the radiation protection organization and maintenance personnel.
Access controls to the RCA were observed and found to be effective.
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Individuals exiting the RCA were required to pass through personnel contamination monitors. Tool monitors were used to survey hardhats.
Radiation protection personnel surveyed hand-carried items for contamination prior to release.
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The Unit 2 steam generator work activities were o' served for radiation o
protection controls.
Radiation protection technicians used appropriate methods to control the spread of contamination, including the designation of hot particle zones.
Hot particle surveys of individuals and equipment were performed properly and at the required frequencies.
- During a tour of the Unit 2 reactor building, the inspector observed individuals working on Valve 2CV-5103-1.
The valve was in a contaminated
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area, and the inspector noted that there was no step-off pad provided for
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workers where they were entering and exiting the contaminated area.
This was-brought to the attention of a radiation protection technician and a step-off
pad was put in place.
Shortly after the step-off pad was put in place,
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two mechanics entered the contaminated area by ducking under the barrier at a place other than the step-off pad.
The inspector reviewed the licensee's
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procedures and noted that the procedures did not address the use of step-off L
pads at contaminated areas. This was confirmed in discussions with the licensee.
The use of step-off pads for entrance and exits to contaminated
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areas is an acknowledged industry good practice.
Not having procedures for
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the use of step-off pads was viewed as a program weakness.
6.6 Maintaining Occupational Exposure ALARA The staffing of the ALARA group was reviewed and determined to be adequate.
t The staff consisted of a supervisor, two dedicated outage planners, two normal j
operations planners, two ALARA coordinators, and an ALARA data coordinator,
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The planners and coordinators worked closely with the plants planning and
scheduling department to effectively incorporate ALARA concerns and reviews
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into work activities and packages.
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The inspector reviewed the Arkansas Nuclear One Five Year Strategic ALARA Plan for the years 1992 through 1996. The plan was comprehensive and aggressively
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pursued a strategy to reduce exposure so that both unit's 3-year exposure l
averages would be in the upper quartile of all PWR plants.
The plan indicated
that management involvement and support of the ALARA plan was excellent as i
evidenced by the number of programs and projects that have been endorsed and financed within the last few years.
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lhe exposure goals for Units 1 and 2 for 1993 were 335 person-Rem and 65 person-Rem respectively.
Unit 2's steam generator outage, which occurred in May, had a goal of 21.73 person-Rem and had an actual exposure of
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20.981 person-Rem.
Included in Unit l's goal of 335 person Rem was 300 l
person-Rem for their Refueling Outage IRll, scheduled for September. As of the end of May, the year-to-date exposure total for both plants was 42 person-
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Rem, which was under the 55 person-Rem goal for that period.
The licensee's
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trending of person-Rem exposures indicated that person-Rem exposures for i
outages are declining.
i The ALARA department employed numerous techniques to achieve Unit 2's goal for i
the steam generator outage.
Some of the techniques included early boration I
and hydrogen peroxide injection to reduce radiation levels; mock-up training I
of the steam generator work; the use of telemetric dosimetry and video cameras to remotely monitor the steam generator work; hydrolazing of the steam generator bowls to remove hot particles and limit contamination; and use of temporary shielding to reduce radiation levels where practical.
Selected ALARA packages for the steam generator outage were reviewed. ALARA packages were found to be of good quality and included adequate checklists, estimates of projected man-hours, radiation survey information, radiation
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exposure projections, and lessons learned from previously accomplished, similar work.
The inspector reviewed the ALARA suggestion program. The licensee had l
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recently implemented a new incentive system for ALARA suggestions that had-increased ALARA suggestions and heightened ALARA awareness.
Minutes of the ALARA committee meetings were reviewed for the period November 13, 1992, through March 18, 1993. Attendance of.the meeting by the-
designated official members had improved since the.last NRC inspection. Minor
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changes to the ALARA charter were made to update the charter, and the meeting
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frequency was changed from bimonthly to quarterly. The minutes reviewed
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indicated that the committee adequately reviewed ALARA concerns.
l 6.7 Conclusions There were only minor equipment and organizational changes to the licensee's radiation protection program. Management support for the radiation protection
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program was very good. The Radiation Protection department had a good working
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relationship with other departments.
Radiation Protection supervisors spent
an appropriate amount of time in the RCA. The audit and surveillance program
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for the radiation protection area was excellent. The audits were.
comprehensive and included a person with technical expertise on the audit
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team.
Responses to audit findings were adequate and timely.
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The licensee's training program for radiation workers and general employees l
was effective.
Staffing of the Radiation Protection department was adequate.
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Screening and training of contract employees was effective.
Qualifications of.
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the radiation protecticn training instructors were appropriate. The licensee had 14 individuals who were registered with NRRPT.
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The licensee's dosimetry program was accredited by-the National Voluntary
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Laboratory Accreditation Program in all categories. Dosimetry was issued and
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worn properly.
Discrepancies between TLDs and SRDs were adequately evaluated.
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RWPs incorporated sufficient radiological controls. A noncited violation was identified for an incident which resulted in an unposted and unguarded LHRA.
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Whole body counts were used appropriately for internal exposure control.
Engineering controls were used to reduce airborne contamination. Air samples
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were representative of the worker's breathing zone.
Respirator fit testing s
was adequate. A noncited violation was identified for failure to inspect and'
operationally check all respiratory protection equipment at least 30 days
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prior to use.
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The' licensee had implemented a good radiation area survey program.
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Housekeeping inside the RCA was effective.
Radiation protection technicians
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provided good coverage of work activities. Hot particle control and surveys were performed properly and at the required frequencies. A weakness was noted for the failure to provide a step-off pad for an entry and exit point to a
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I contaminated area and for personnel entering a contaminated area at a place
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other than at the step-off pad.
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ALARA staffing was adequate. The licensee's Five Year Strategic ALARA Plan was very good.
Management involvement and support for the ALARA plan was
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excellent.
The licensee was under their total person-Rem goal for 1993.
The
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ALARA program used numerous effective techniques to lower annual person-Rem.
ALARA packages were of good quality.
Jhe licensee's ALARA
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suggestion program was very good and has helped to increase ALARA awareness.
ALARA committee meeting attendance had improved.
7 FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS AND DEVIATIONS (92702)
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7.1 (Closed) Violation 368/9225-01:
Failure to Attend Prejob Briefings l
i This item involved the identification of approximately 20 people performing i
work under RWP 921392 without attending radiologicai prejob briefings.
This violation was last reviewed in NRC Inspection Report 50-313/93-03;
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50-368/93-03.
The violation was not closed out in that report due to minor l
administrative problems that allowed the addition of personnel to RWPs that were not on a prejob briefing list.
The licensee's corrective actions to ensure that individuals that were put on an RWP or had actually entered and performed work activities on an RWP received a required prejob briefing were reviewed and found to be acceptable.
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The inspector reviewed selected RWPs that required prejob briefings and noted
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that everyone that was signed in on the RWP or had entered and performed work
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under the RWP had attended a prejob briefing.
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8 ONSITE FOLLOWUP OF LICENSEE EVENT REPORTS (92700)
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8.1 (Closed) Licensee Event Report 313/91-003:
" Actuation of the Emergency Feedwater System During Plant Heatup due to Low Once through Steam Generator level Which Resulted From Inadequate feedwater flow caused by
a Degraded Auxiliary Feedwater Pump"
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This licensee event report involved an actuation of the emergency feedwater system which occurred due to low once through steam generator (OTSG) level.
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This event was reviewed and documented in NRC Inspection Report 50-313/91-17, 50-368/91-17.
At the time of the event OTSG levels were being lowered to
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30 inches in preparation for plant startup.
When OTSG "A" reached its
programmed level, Auxiliary feedwater Pump P-75 was unable to maintain the
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required level. As OTSG level continued to decrease, the emergency feedwater system automatically actuated.
l The root cause of the event was originally determined to be leakage past the seat of Valve FW-8A, which was a bypass valve to the condenser.
Valve FW-8A
was repaired per J0 00861040.
Procedure 1102.02, Revision 49, " Plant
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Startup," was revised to incorporate the requirement to have Bypass
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Valve FW-9A closed, whenever Bypass Valve FW-8A was required to be closed, and
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to verify the ability of Auxiliary feedwater Pump P-75 to feed the OTSGs prior
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to reaching 0TSG low level limits.
Subsequent disassembly and inspection of Auxiliary Feedwater Pump P-75 during
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Refueling Outage IR10, revealed that the actual root cause of the event was a -
loose first stage channel ring bushing which reduced the inlet area to the.
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second stage impeller and resulted in decreased pumping capacity at increased
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flow rates. Auxiliary Feedwater Pump P-75 was repaired and satisfactorily tested during Refueling Outage IR10 under JO 00847036.
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ATTACHMENT
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1 PERSONS CONTACTED 1.1 Licensee Personnel
- D. Boyd, Licensing Specii. list
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+S. Cotton, Radiation Protection and Radwaste Manager
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- R. Douet, Unit 1 Maintenance Manager
- B. Eaton, Design Engineering Director
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- R. Edington, Unit 2 Plant Manager
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- J.
Fisicaro, Licensing Director
- M. Harris, Unit 2 Maintenance Manager
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- B. Haylock, Unit 1 Technical Assistant
- L. Humphrey, Quality Director
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+R. King, Plant Licensing Supervisor
- D. Moore, Health Physics Operations Superintendent
- T. Nickels, Health Physics Specialist
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+*M. Sellman, Plant Operations General Manager
- D. Snellings, Radiation Protection Superintendent
- D. Wagner, Quality Assurance Supervisor 1.2 NRC Personnel
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+*S. Campbell, Resident Inspector
+L. Smith, Senior Resident Inspector
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+A. Gaines, Acting Resident Inspector
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In addition to the personnel listed above, the inspectors contacted other personnel during this inspection period.
- Denotes personnel that attended the exit meeting on May 28, 1993.
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+ Denotes personnel that attended a postexit meeting on June 10, 1993.
i 2 EXIT MEETING
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An exit meeting was conducted on May 28, 1993.
During this meeting the
inspectors reviewed the scope and findings as detailed in this report. The
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licensee did not identify as proprietary any information provided to, or reviewed by, the inspectors.
A postexit meeting was conducted on June 10, 1993.
During this meeting the
licensee formally committed to planned corrective actions associated with the
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two noncited violations.
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