IR 05000313/1993008
| ML20059K536 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 11/08/1993 |
| From: | Stetka T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20059K513 | List: |
| References | |
| 50-313-93-08, 50-313-93-8, 50-368-93-08, 50-368-93-8, NUDOCS 9311160090 | |
| Download: ML20059K536 (25) | |
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. APPENDIX B U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Inspection Report: 50-313/93-08 ' 50-368/93-08
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Licenses: DPR-51 NPF-6 .
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Licensee: Entergy Operations, In Route 3, Box 137G Russellville, Arkansas facility Name: Arkansas Nuclear One, Units 1 and 2 Inspection At: Russellville, Arkansas Inspection Conducted: August 22 through October 2, 1993- , Inspectors: L. Smith, Senior Resident Inspector S. Campbell, Resident Inspector Accompanying Personnel: K. Weaver, Engineering Aide
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Approved: /_d ww 7 Thoma's F. Stetki, Chief, Project Section D
/l[8 f93 Datt Inspection Summary
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Areas Inspected (Units I and 2): This routine, unannounced inspection addressed onsite event followup, operational safety verification, monthly maintenance observation, observation of bimonthly surveillance, followup on previous inspection items, and onsite review of licensee event reports (LERs).
Results (Units 1 and 2):
* The power reduction in response to a major Unit 2 condenser tube leak was well controlled. Cleanup activities'were carefully planned (Section 2.1).
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* Unit 1 personnel were responsive when a polar crane problem developed, and they carefully placed the reactor vessel head on temporary cribbing when the polar crane was unable to lift vertically (Section 2.2).
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9311160090 931109 ' PDR ADOCK OSDOO310F G PDR
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* Failure to administrative 1y control Unit I-nitrogen isolation -
valves for containment integrity was a deviation from the Final Safety Analysis Report (Section 3.2).
- The blocking of the suction source for Unit 1 electrical '
penetration room Ventilation Blower VEF-38B which rendered the blower inoperable was a weakness. Discovery of the deficiency was - a strength (Section 3.3).
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' * Failure to install endcaps on safety-related piping stored in a Level D storage area constituted a deviation from the Quality ,
Assurance Manual Operations (Section 3.4).
- The physical security organization effectively prepared security logs, investigation, and observation reports. Licensee security ;
personnel were both-knowledgeable of the site security plan (Section 3.5). j
* The inspector identified a fallen high radiation area posting and_ !
a contaminated area posting. The licensee promptly repaired the 1 posting and was evaluating measures to prevent recurrence ,
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* Unit 2 conservatively responded to the loss of incore issue by requesting an early Technical Specification change. Further, the licensee conservatively entered Technical Specification 4' .
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while the intent of a surveillance re:;uirement was being evaluated by the NR * Procedural deficiencies which resulted in flush water being i discharged to the lake in excess of the environmental pH outfall , limits was a weakness (Section 3.10). ,
* Response to the NRC Information Notice 91-74, " Changes in .
Pressurizer Safety Valve Setpoints before Installation," was not ! aggressive (Section 3.15). .
* The overall refueling outage planning was excellent. The overal schedule was risk based. Controls to ensure the basic outage a-windows were adhered to were effective (Section 3.16).
* Maintenance activities observed were performed well- and in !
accordance with procedures. The presence of management at a
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worksite was indicative of strong management-oversight. The- , failure to alert workers to a change in a valve position was a weakness (Section 4.4). ,
* Observed surveillance activities were safely conducted in .
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accordance with procedures (Section 5.3).
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Summary of Inspection Findings: ;
* Deviation 313/9308-01 was opened and closed (Section 3.2). : * Deviations 313/9308-02; 368/9308-02 were opened and closed - (Section 3.4). . * Temporary Instruction 2500/028 was closed (Section 6).
- LER 368/91-006 was closed (Section 7).
- LER 368/92-003 was closed (Section 7). -
Attachments:
* Attachment 1 - Persons Contacted and Exit Meeting
* Attachment 2 - Employee Concerns Program
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DETAILS 1 PLANT STATUS 1.1 Unit 1
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At the beginning of the inspection period, Unit I was at 100 percent power.
L On September 1 the unit experienced a power oscillation due to Moisture l Separator Drain Tank Valve CV-3025 sticking at the 75 percent open position l which caused Feedwater E-1B high level dump valve to open and main feedwater pump suction pressure to decrease. The unit was stabilized,at 98 percent power and returned to 100 percent power the same day. On September 3 Unit I began a power coastdown in preparation for Refueling Outage IRll. On September 6 the unit commenced a power reduction at 25 percent.per hour. The main generator output breakers were opened, the main turbine was tripped, and Refueling Outage IR11 began shortly after midnight on September 7. At the end of the inspection period, the unit remained in Refueling Outage IR11.
' 1.2 Unit 2 At the beginning of the inspection period, Unit 2 was at 100 percent powe On August 22, the unit reduced power to approximately 60 percent per the load dispatcher's request. The unit returned to 100 percent power on August 2 On September 17 the unit commenced a power reduction due to condenser-tube leakage. The turbine was manually tripped on September 18. Following condenser tube repairs and main feedwater system chemistry cleanup, the unit returned to 100 percent power on September 22. At the end of the inspection period, Unit 2 remained at 100 percent powe ,
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2 ONSITE EVENT FOLLOWUP (93702) .
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2.1 Unit 2 - Condenser Tube Leak At approximately 11 p.m. On September 17, the licensee detected a large condenser tube leak. Over 3,000 parts per billion sodium were detected in the feedwater system. The inspector observed portions of the power reduction in response to the leak, Command and control during the power reduction was excellent. The shift supervisor effectively supervised the power reduction, reviewed planned repair activities, and briefed plant managemen Power was initially reduced so the licensee could isolate the inner pass of the main ; condenser to stop the leak. The licensee then decided to further reduce reactor power to 5 percent for cleanup to less than 100 parts per b'llion ; sodium. The licensee entered the B south water box of the main condenser and 1 identified that a tube had sheared. The sheared tube and the surrounding , tubes were plugged. Following placing the water box back in service, a boric : acid soak was performed. Reactor power was then increased to 30 percent to l complete cleanup activities and to ensure that the sodium level was less-than
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20 parts per billion. The plant returned to full power on September 2 l
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l l-5-I 2.2 Unit 1 - Reactor Vessel Head lift , On September 17 the inspector observed the reactor vessel head.. lift during ;
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l Refueling Outage.1Rll from inside the reactor. building and from the licensee's audio visual display located at a controlled access point. During the lift, i ! the polar crane's main hoist vertical motion was stopped and the head was : trollied horizontally in the refueling canal. When the lift was resumed,.the' ! main hoist motor could not reestablish vertical motion. Subsequent attempts
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l were made to reestablish vertical lift; but during each attempt, the head ! lowered slowly instead of rising. The vessel head was suspended from the r polar crane for several hours while the licensee made preparations to lower the head onto temporary cribbing in the refueling canal. Further information ' regarding the polar crane's lifting problem is documented in NRC-Inspection Report 50-313/93-26; 50-368/93-2 The inspector attended all crew briefings and radiation work permit briefings performed throughout the troubleshooting activities. Prior to each individual ' evolution, a thorough crew and a radiation work permit briefing was performed-for personnel involved. Health physics technicians also continuously , monitored current radiation levels for the areas surrounding the vessel head where the troubleshooting activities were performed. The personnel involved in the troubleshooting activities and the radiation level monitoring displayed a strong sensitivity to both equipment and human safet ; 2.3 Conclusions , The power reduction in response to a major Unit 2 condenser tube leak was well ' controlled. Cleanup activities were carefully planned. Unit 1 personnel were effective in placing the reactor vessel head onto temporary cribbing when the ; polar crane was unable to lift the hea OPERATIONAL SAFETY VERIFICATION (71707) 3.1 Unit 1 - Repair of Service Water Return Header l A small pinhole leak in the service water return header was identified by the licensee on August 2,1993, and evaluated in NRC Inspection Report 50-313/93-07; 50-368/93-07. The leak was on a return header which was . I not isolable, was common to both trains, and was needed continually for decay heat removal. The inspector reviewed both draft and final plans to make the I repair to ensure that the integrity of the service water system would not be adversely affected by the repai The licensee evaluated several repair options and decided to install .a 2-inch, 3,000-pound threaded half coupling with a threaded pipe plug over the leak. A sheet metal screw was threaded into the leak while the weld was made. Then-the half coupling was welded onto the service water piping. The licensee's - position was that this option provided fewer operational concerns than isolating service water and draining the header while fuel was in the reactor Cor !
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l i l- -6-t l > 3.2 Unit 1 - Control of Primary Containment Isolation Valves !
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On August 6 the inspector observed sampling of the reactor building sum ; During that evolution Drain Valves DWD-4411 and DWD-4448 were opened to take the sample. The valve manipulation was controlled by Procedure 1104.014, . Revision 17, " Dirty Liquid Waste and Drain Processing." The valves were in series on a 3/4-inch line that reduced down to a 3/8-inch line.- The line .,
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penetrated a 4-inch line that was used to drain the reactor building sum The penetration was outside of containment but before the. outboard primary i containment isolation valve. When the valves were opened, the licensee did not enter Technical Specification 3.6.1 which required reactor building ! integrity. Technical Specification Definition 1.7. c.. defined reactor i building integrity as "all non-automatic reactor building isolation valves and i blind flanges are closed as required." Choosing to not enter Technical ; Specification 3.6.1 when the valves were opened, was a change in J interpretation. The licensee used an example from Generic Letter 91-08, .
" Removal of Component Lists from Technical Specification," to interpret that manipulating a valve on an intermittent basis using administrative controls ;
was acceptable. The valves were, therefore, not recuired to be closed at all '
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times. Administrative controls were added to Procedure 1104.014 and a 10 CFR 50.59 review was performed prior to approval on July 27, 199 { The inspector questioned the licensee's commitment to 10 CFR Part 50, Appendix A, Criterion 56. Valve DWD-4411 appeared to be a primary containment isolation valve but was not listed in Table 5-1 of the Unit 1 Safety Analysis : Report. Criterion 56 required that "Each line that connects directly to the ! containment atmosphere and penetrates primary reactor containment shall be provided with containment isolation valves as follows unless it can be demonstrated that the containment isolation provisions for a specific class of_ ! lines . . . are acceptable on some other defined basis . . . . " The licensee ' stated that the underlying assumption of their licensing basis was that drain ' lines, vent lines, integrated leak rate test lines, and instrument lines were not designed to meet Criterion 56; however, this particular drain line was now . being used as a sample line. As a result, the licensee had assigned i responsibility for initiating Licensing Document Change Request 1-5.229 on 1 July 8,1993, to update the Safety Analysis Report to reflect opening the .! reactor building sump isolation valves under administrative controls. The l licensing document change request was approved August 31, 199 l The licensee, further, stated that the normal configuration for vent, drain, and test connections would be either a double set of closed valves or one .! j closed valve with a pipe cap. The inspector selected vent, drain, and test ' connection lines that contained valves that would otherwise be included under the scope of 10 CFR Part 50, . Appendix A, Criterion 56, to evaluate the program for controlling the configuratio Isolation via either double valve closure . or valve closure with pipe cap verification for the majority of the lines was 'j controlled by Procedure 1102.001, " Plant Preheatup and Precritical Checklist," ' Revision 51, Permanent Change However, Valves BS-2407 and BS-2408 were verified in Procedure 1104.005, Revision 32, " Core Flood System Operating Procedure," to be closed but the corresponding pipe caps were not procedurally i i
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installed. The failure to procedurally confirm the installation of the pipe ' caps was determined to be a weaknes The inspector. reviewed the operational controls for primary containment isolation valves. Table 5 I of the Safety Analysis Report required that
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Nitrogen Isolation Valves N2-54 and N2-51 be locked closed. These valves were - not on Attachment E of Procedure 1102.01, " Category E Valve Position Verification," Revision 51. This attachment was normally used to identify - valves that required lecks. On September 3 the inspector confirmed the valves were closed; however, they were not locked. This was a deviation from Table 5-1 of the Safety Analysis Report (313/9308-01).
Nitrogen Valves N2-51 and N2-54 were locked closed in accordance with Safety Analysis Report Table 5-1 upon identification. The licensee reviewed the remainder of the table for potential deviations to the Safety Analysis Report .,
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for normal valve lineup and locked closed status. No other deviations were identified. The licensee committed to revise the appropriate operating procedures to require that Valves N2-51 and N2-54 to be normally locked closed by October 14, 199 .3 Unit 1 - Inoperability of Electrical Penetration Room Blower VEF-38B ,
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At 10 a.m. on August 24, licensee personnel discovered the electrical penetration room Ventilation Blower VEF-38B suction pipe covered with plastic, which rendered the blower inoperable. The plastic was installed by instrumentation and control technicians to protect the pipe from the spread of contamination while performing electrical penetration leak rate testing. The .
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licensee entered a 7-day time clock per Technical Specification 3.13.2. Upon removal of the plastic at 4:35 p.m., the licensee exited the specification . time cloc l a
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The inspector verified that Train A, the redundant electrical penetration room Ventilation Blower VEF-38A, remained operable when Train B was inoperabl ; Ventilation Blowers VEF-38A and VEF-38B were provided to exhaust air in the : electrical penetration rooms to the outside. Ventilation Blower VEF-38A .! actuated automatically on an engineered safety signal to minimize the spread l of high airborne activity from the reactor building to the. auxiliary buildin Ventilation Blower VEF-38B, which was the standby system, automatically ! started if VEF-38A did not achieve proper flow within 20 second '
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The inspector determined that the ventilation suction was covered because the~ ! piping was not labeled and, as a result, the technicians did not recognize the 1 requirement to not block the airflow. The inspector concluded that the event
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was not a violation of the licensee's work control program.- The blocking of the-suction source for Ventilation Blower VEF-3BB, which resulted in the i blower being rendered inoperable, was determined to be a weakness.
' Identification of the inoperable equipment by licensee personnel was considered to be a strength. The licensee's corrective action, which was
.cocumented on a nonsignificant condition report, was to add labeling in each l
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of the penetration rooms to alert personnel to special conditions in the rooms.
l 3.4 Units 1 and 2 - Control of Material Storace for Level D Items On September 2 the inspector conducted an inspection of the licensee's Level D storage laydown area. As the result of this inspection, endcaps were noted ' missing from stored, safety-related pipe sections and pipe elbows and corrosion was noted on internal surfaces as well as exterior surfaces. The , corrosion buildup on the exterior surfaces, in some cases, affected the ' legibility of stencil labelin Examples of the safety-related piping and piping elbows were 10-inch, Schedule 12 pipe with Stock Number 505-6740 and Heat Number L40629, and a Class 3, 90 degree elbow with Stock Number 507-9942,_ and Heat Number HEGY. Safety-related plates of carbon steel were' also noted with surface corrosion. Some specific examples were a pallet of carbon steel plates with Stock Number 502-7065 and Heat Number Y2793, and another pallet of carbon steel plates with Stock Number 502-7067 and Heat Number Y273 . The licensee's quality assurance program required compliance with ANSI N45.2.2-1972. ANSI N45.2.2 defined activities for the handling, storage, , and shipping; including cleaning, packing, and preservation of materials and i equipment. The inspector reviewed Procedure 1033.002, Revision 25, " Control l of Material," to verify that the requirements defined in ANSI N45.2.2 were l incorporated. Procedure 1033.002, Section 6.3, " Levels of Storage for , Q/F Materials," defines Levels A, B, and C storage requirements. However, l Level D requirements were not included in that section of the procedure'. , The licensee stated that even though Section 6.3 did not include Level D l storage requirements, the requirements for Level D storage were incorporated ' in the procedure in Section 6.1. The inspector verified that the requirements were incorporated in Section 6.1; however, the requirement as specified in ANSI N45.2.2, Section 3.2.4(3), that items subject to detrimental corrosion, either internal or external shall be suitably protected, or the requirement specified in Section 3.2.4(5) that items such as aggregate and reinforcing steel shall. be suitably protected against detrimental contamination or l corrosion were not included in Procedure 1033.00 The licensee stated that items stored in the Level D storage area were not j subject to detrimental corrosion, even though no protection from outside l weather conditions was provide Several worse case examples of corroded pipe ) and plate were selected by the licensee for further examination. In all cases- ._ the licensee stated the material was still within the purchase specification ; requirements with respect to minimum wall thicknes ' Procedure 1033.002, Step 6.1.7, directed monthly inspections of storage facilities which included a checklist to document the inspection which included pipe endcap integrity as a checklist item. The licensee provided the monthly inspection checklists for the previous two months, however, no mention of missing endcaps were identified by the licensee's inspection. Based on the condition of several sections of pipe and pipe elbows, it appeared that this l j_ !
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provided procurement documentation which indicated replacement endcaps had ' been requested on July 16, 199 i Failure to maintain endcap integrity for safety-related piping in Level D storage constitutes a deviation from the licensee's commitment to ANSI N45.2.2-1972 for the packaging of safety-related items in storage (313/9308-02; 368/9308-02). In order to address the deviation, the licensee
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initiated Condition Report C-93-0108. As part of their corrective actions, , the licensee inspected and installed all missing pipe caps in the Level D . storage areas. Nondestructive examinations were performed.on'19 items located in the Level D storage area with the highest visible corrosion, and all items passed the minimum specified thickness requirements. Additional training was provided to storeroom personnel concerning ANSI storage requirements. The licensee also committed to revise Procedure 1033.002 on October 12 to include-a description of Level D packaging storage requirements. Based on the extent of the licensee's corrective actions, no further response to this deviation is , require .5 Units 1 and 2 - Physical Security Insoection On September 2 the inspector conducted an audit of the security records, which included the third quarter security logs and the investigation and observation reports. The reports reviewed covered the period from June 6 through' ' September 1, 1993. The threshold for documenting events from the investigation and observation reports into the security logs met the requirements specified in Procedure 1043.040, Revision 19, " Investigating and Reporting Security Related Incidents." The licensee provided excellent documentation of the events in the observation and investigation report e The inspector briefly reviewed Revision 27. to the Industrial Security Plan dated March 17, 1993, . prior to accompanying the licensee security personnel on a tour around the perimeter of the protected area. During the tour,.the ,
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inspector questioned the individuals in regards to the industrial securit plan. The licensee security personnel were knowledgeable about the industrial security plan and how it applied to the plan ' The' protected area fence was intact with no unusual objects or personnel located in the isolation zone ' Subsequent review of the Morse watchman printout following the perimeter tour ~ indicated that security personnel appropriately logged at all Morse watchman ' stations located around the perimeter. The security personnel conducted an-excellent tour of the perimete , 3.6 Units 1 and 2 - Combustible Material Control j On September 7 the inspector observed two untreated wooden pallets located i the train bay in the radioactive materials area and noted that a fire watch was not present. The inspector informed the licensee about the conditio ;
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I Approximately 1/2 hour later, the inspector identified an additional untreated-wooden crate in the same locatio t The inspector reviewed Procedure 1000.047, Revision 10, " Control of Combustibles," and concluded that the material was classified as a transient combustible. Attachment 1 of the procedure, " Compensatory Measure Guidelines for Transient Combustibles," does not require continuous personnel attendance for transient combustibles located in the turbine building which was * considered a low fire hazard area. The licensee stated they prefer.ed to-- minimize the amount of transient combustibles in that area. The inspector concluded that the condition was acceptabl i Units 1 and 2 - Routine Tours On September 14 the inspector identified a radiation hot spot with one of the licensee's radiation detection instruments which indicated approximately 200mR/hr on contact and approximately 50mR/hr at I foot. The hot spot was located on the CZ-16 flush connect pipe elbow in the Unit I auxiliary building equipment Drain Tank Pump P-46 room. The hot spot was not labeled on the pipe elbow nor marked on the radiation area survey map. The inspector notified licensee personnel of the finding. Licensee personnel promptly surveyed the pipe, posted a hot spot label on the pipe, and identified the hot spot on the radiation area survey ma On September 29 the inspector identified two radiation postings and rope i barriers located on the floor in Unit 2. One of the postings stated
" Contamination Area." The other posting was face down on the floor and the radiation information could not be identified for the area of concern. The inspector notified licensee health physics personnel of the finding. Licensee personnel reconnected the rope barriers, repositioned the postings, and resurveyed the area for radiation and contamination. The radiation posting that was identified face down on the floor stated "High Radiation Area." The licensee stated that the rope barriers adhesive tab had pulled loose from the wall and allowed the barriers and postings to fall to the floor. While the I area had been correctly posted, the failure to maintain the radiation barriers and radiation postings intact was apparently an isolated occurrence and not indicative of a programmatic problem. Licensee radiation protection personnel stated that while fallen i.ostings were very infrequent, they' had occurred previously in areas of high use or high humidity. Further, the licensee had implemented a zone p Health physics technicians were responsible for ensuring various zon,rogram.es in the auxiliary building were appropriately posted and that work activities were appropriately controlled. This made it unlikel that the posting had been down for an extended period or that work activities had been conducted in the vicinity of the fallen posting. The licensee was evaluating the use of metal plates with a different adhesive to provide a more secure anchor for the posting r i
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3.8 Unit 2 - Incore Detector Failures t On September 16 the licensee notified the inspector that a marked increase in .
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incore detector failures occurred over the previous weekend. Technical- . Specifications required a minimum of 165 incore detectors or a minimum of 33 locations operable. Each location contained five detectors. Failures below the minimum number required reducing plant power to approximatel '
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85 percent power because the core operating limit supervisory-system (COLSS), , would be considered inoperable. The incore detectors were not used to actuat * any safety functi s, but they did provide an alarm function via the COLS ! The COLSS would al rt the operators if the core operating limits were being exceede The licensee proposed an exigent change to Technical Specification 3.3. based on bounding engineering Judgement supplied by the vendor for operating the unit with 110 incore detectors or 22 locations until the next refueling-outage. The licensee drafted a continued safe operation determination as a , contingency to support a request for a three-week enforcement' discretion, which would permit the plant to continue operating at 100 percent power,-if the number of detectors fell below the operability limit while the exigent Technical Specification change was being reviewed. At the end of the inspection period, there were 174 operable incore detectors and 35 operable locations. The inspector concluded that the licensee was proactive in requesting an exigent Technical Specification change prior. to the last incore detector failin .9 Unit 1 - Cross Tie of Safety-Related Busses A-3 and A-4 , On September 16 the inspector noted that the licensee cross-tied the ' 4160V safety-related Busses A-3 and A-4 Juring the nonsafety-related - Bus A-1 outage. Upon questioning the licensee regarding this electrical configuration, the licensee provided breaker coordination studies and data for ~ the largest motor inrush current for spurious motor start to the inspecto The coordination study indicated that the cross tie hreakers opened to separate Bus A-3 from Bus A-4 followed by the opening of the supply breaker from Bus A-2 to Bus A-4, therefore, preventing the loss of both busses simultaneously. The inspector concluded the cross tying of buses was acceptabl .10 Unit 1 - Flush Water Discharged to Lake above Environmental Limits On September 16 the licensee exceeded the environmental outfall pH limits of 6.0 - 9.0 when flush water from a temporary filling assembly for the Unit 1 - once through steam generator-was discharged to the -lake. The 3,200 gallons of-flush water released during the evolution had a pH level of 9.2 and was ~of-little or no impact to the environment. The licensee notified the Arkansas Department of Pollution Control and a subsequent 4-hour report was made to the NRC upon discovery of the discharg ,
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i The licensee stated that the elevated pH was attributed to flushing of residual water left in the piping following a previous once through steam i generator wet lay up fill. Water to the once through steam generator required the addition of ammonia and hydrazine in order to bring the pH specifications ( to between 9.8 and 10.5. The condition did not occur during previous ; l discharges because a quick refill of the steam generators was uncommon. The quick refill of the steam generator did not allow sufficient time for the pH ' l level to decrease below 9.0 in the discharge pipin Procedure 1628.008, Revision 1, " Chemistry Support for Placing U-1 Steam j Generators in Wet Lay-up," required the pH limit for flushing the servi water header to the flume to be 6.0 - 9.0. The licensee sampled the flush ; water as required by procedure at the flume. The sample pH level was found to l be Sampling could only be performed at the flume during a discharge to the lake. Therefore, the residual water in the piping was discharged to the ; lake while taking a sample at the flum l
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The inspector concluded that procedural deficiencies, and not failure to follow procedures, caused the high pH discharge to the lake. As the result of ' this event, the licensee revised the procedure to flush to the turbine r ' building trench rather than the lake. The inspector considered the procedure change appropriate, but the procedural deficiency was considered to be a weaknes , 3.11 Unit 2 - Loss of Instrument Air i On September 17 an instrument air line break occurred at a soldered joint. As a result, the valves to the condenser vacuum pumps failed shut and the stator water cooling valves failed open. The air line break was repaired before a
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significant loss of vacuum occurred. Condition Report 2-93-0220 was l initiated, determined significant, and was scheduled for a Corrective Action Review Boar ;
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Due to a recurrence of instrument air line and soldered joint failures on , Unit 1, the licensee developed and was in the process of implementing an Instrument Air Integrity Program as documented in previous Condition l Report 1-91-022 As part of the corrective action for Condition Report 1-91-0222, an Instru1ent Air Integrity Program was also developed and in the process of being implemented for Unit 2 but was not yet complet .12 Unit 1 - Loss of Power to Temporary Core Exit Thermocouple (CET) Two independent CETs were installed during Refueling Outage IR11 to provide ' alternate reactor coolant temperature indication in the reactor vessel via the safety parameter display system when the normal CETs were withdrawn. The temporary CETs were required to be available by the shutdown operations ; protection plan. On September 22 temperature indication from the temporary CETs dropped unexpectedly from 104 F to 25 F when Inverters Y-25 and Y-26 were deenergized for a battery modificatio !
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Deenergizing Inverters Y-25 and Y-26, deenergized the plant computer and, ! consequently, prevented the_ reference junction temperature signal, which was routed through the plant computer, from reaching the safety parameter display system. The licensee restored the CETs to an operable status by providing an artificial reference junction temperature of 80"F to the safety paramete l display system while the plant computer was deenergized. The fact that the temporary CET reference junction temperature signal was routed through the i
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plant computer was not recognized by the licensee when the inverter outage was - planne . The loss of the temporary coolant temperature indication was of minor safety : significance. However, the licensee's oversight in recognizing the impact of deenergizing the inverters resulting in the loss of coolant temperature ; indication was a weakness. The prompt recognition and restoration of the lost ' coolant temperature indication was a strengt .13 Unit 2 - Power Ascension Following Condenser Tube Repairs On September 30 the inspector observed the power ascension from approximately 29 percent to 100 percent following condenser tube repair ,
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The inspector concluded that the power ascension was performed well by the license .14 Unit 2 - Partial Stroking of Safety-Related Injection Valves ! During a review of the station logs, the inspector noted that on several occasions various emergency core cooling system (ECCS) safety injection valves were being partially stroked to fill leaking safety injection tanks without subsequent verification of the valve's position stop. Technical , Specification 4.5.2.g required a verification of the correct position of'the l electrical and/or mechanical position stop within 4 hours following completion '
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of a valve stroking operation for these valve . The inspector questioned the licensee's interpretation of the surveillance requirement regarding stroking of the safety injection valves. The licensee stated that it was their position that only a full stroke of the ECCS safety injection valves required position verification in accordance with the ; Technical Specification ; Following review of this issue by the NRC, it was det' ermined that partial l stroking of the emergency core cooling throttle valves did not require l' verification of the valve position stop and that, therefore, the licensee's activities were in accordance with their Technical Specification l4 3.15 Unit 1 - Pressurizer Code Safety Setpoint Drift During the performance of the regularly scheduled surveillance for setpoint testing of Pressurizer Safety Valve PSV-1002, the setpoint was found to be out of tolerance. The required setpoint for Valves PSV-1001 and PSV-1002 was 2500 psig +1 percent to -3 percent. The "as found" setpoint for
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Valve PSV-1002 was 2578 psig. Condition Report 1-93-0337 was initiated and an engineering evaluation was performed. As the result of this evaluation, the licensee determined that Valve PSV-1002 satisfied the requirements of the ASME Code and was, therefore, operabl Subsequent setpoint testing was performed on Valve PSV-1001 and the
"as found" setpoint was also found to be out of tolerance at 2613 psig. The licensee planned to evaluate the past operability of Valve PSV-1001 on
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Condition Report 1-93-347; however, the analysis was not yet complet The inspector questioned the licensee if the recommendations of ;
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NRC Information Notice 91-74 " Changes In Pressurizer Safety Valve Setpoints Before Installation" regarding performance of the jack-and-lap procedure after setpoint testing, had been incorporated during the previous setpoint testing t of Valves PSV-1002 and PSV-1001. The licensee stated that the recommendations : had not been incorporated into the previous setpoint testing methodolog NRC Information Notice 91-74 was received and distributed only three months : prior to Refueling Outage IR10 and was still under review with the valve q a vendor when the previous testing was performed. The licensee stated that currently all pressurizer code safety valves had been refurbished, retested, and the setpoints reset using the new method which incorporated the recommendations of the NRC Information Notice 91-74. The inspector reviewed Condition Report 1-93-0337 and concurred with the engineering evaluation. The inspector also concluded that the timeliness of incorporation of the : recommendations of NRC Information Notice 91-74 was acceptabl .16 Unit 1 - Observation of Operations Activities during Refuelinq ! Outage IRll The inspector noted substantial improvements with regards to the shutdown .
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operations protection plan (SOPP), scheduling, radiation protection, and control of work activities during the 44-day planned refueling outag The use of SOPP guidelines in conjunction with outage risk assessment- ; management enhanced managing the outage from a risk based perspective. While ; the unit was in reduced inventory, operations safely utilized the S0PP , condition requirements, which provided minimum equipment requirements to protect the reactor coolant system while in shutdown conditions. The licensee , provided special protection for electrical system trains needed for decay heat i removal. The trains were controlled by roping off protected areas. The 1 inspector periodically checked the protected trains and verified that j administrative controls were in place. Work activities on the protected : trains were not prohibited; but, rather scrutinized by the support shifts for i adverse impact on the plant; thereby, alleviating administrative burden on the ;j operations crew. The inspector did not identify or observe any evolution-g which adversely impacted the protected train The. licensee conducted daily morning outage meetings which were attended by a 1
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majority of the managers and their representatives, superintendents from various departments, and contractor representatives. The outage desk issued a i
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l daily shift outage meeting report which was an excellent tool for ; communicating potential scheduling impacts and scheduling expectations during ; the morning meeting to each responsible individual. Coordination problems associated with equipment outages and tagouts were corrected by conducting midshift emergent work meetings to streamline work activitie Shutdown chemistiy controls for source term reduction, including early j boration and hydrogen peroxide flushes, resulted in a reduction of radiation - ' levels in several areas of the plant by approximately 50 percent. At the end of the inspection period, which was day 26 of the outage, approximately 137 man-rem outage exposure was accumulated by plant personne The licensee o stated that approximately 121 man-rem of exposure was avoided as a result of ' the early boration and hydrogen peroxide flushe ; 3.17 Conclusions Two weaknesses were identified on Unit 1 prior to the start of the outag ' The licensee identified that electrical penetration room Ventilation Blower VEF-38 was inadvertently rendered inoperable when plastic was placed , over the suction piping. This was discovered prior to exceeding the allowed outage time but indicated lack of adequate information flow. Similarly, the l primary containment isolation valve list in the SAR was updated to add-locks-l to nitrogen valves without coordinating with operations. As a result, the locks were not placed in the field and resulted in a deviation from the SAR commitments (313/9308-02).
The overall refueling outage planning was excellent. The overall schedule was risk based and pr eided appropriate controls to ensure that the basic outage l windows were fol- ,ed and effective. The service water return header repair l effort was caref ui ty evaluated. The cross tie of the' two safety-related l electrical busses was also carefully evaluated. However, response'to the NRC Information Notice 91-74, " Changes in Pressurizer Safety Valve Setpoints before Installation," was not aggressive. As a result, the pressurizer safety valves were found out of tolerance for reasons that could have been prevente Procedure preparation for the flushing of the steam generator was not adequate and resulted in exceeding pH limits for water that was discharged to the lak Planning for the battery modification did not adequately account for temporary core exit thermocouple Unit 2 conservatively responded to two issues with their Technical-Specifications. When questioned regarding the implementation of Surveillance . Requirement 4.5.2.g, the licensee implemented the most conservative ! interpretation while the issue was being reviewed. fhey also detected a failure trend for incore detectors and prepared an exigent Technical Specification change request promptly. The power ascension following the , condenser tube leak was well controlle l
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The physical security organization effectively prepared security logs, . investigation, and observation reports. The licensee security personnel were , both knowledgeable of the site security pla ! l
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. -16-The inspector identified a fallen high radiation area posting and contaminated area posting. While the area was posted, the effectiveness of the posting was greatly reduced. The licensee promptly repaired-the posting. The Radiation Protection /Radwaste Manager was notified and was evaluating measures to prevent recurrence. The hot spot discovered by the inspector was attributed to changing plant condition '
The failure to maintain endcap integrity for safety-related piping in Level D storage areas was a deviation from the licensee's commitments. The licensee's inspection of endcap integrity was not accurately documented to indicate lack of endcaps; however, procurement of endcaps was in progress. The licensee stated that the need for endcaps was under revie MONTHLY MAINTENANCE OBSERVATION (62703) 4.1 Unit 2 - Replacement of Postaccident Sampling System (PASS) Rupture Disc (JO 00898744) On September 1 the inspector observed replacement of PASS Hydrogen Analyzer Outlet Rupture Disc 2PSE-5995 in accordance with the job order. The licensee entered a 7-day action statement when the system was declared inoperable for replacement of the rupture disc as required by a commitment to the NRC. The technicians obtained and installed the new rupture disc in accordance with the' vendor technical manual and the job order. 'All activities, includin compliance to the radiation work permit and postmaintenance testing were adequately performe .2 Unit 2 - Replacement of High Pressure Injection System Pump 2P89C Discharge Stop Check Valve 251-100 (JO 00893901) On September 9 the inspector observed the replacement of Discharge Stop Check Valvo 251-100. The valve was being replaced because it had a damaged sea The licensee established the appropriate fire prevention and protection controls by utilizing qualified fire watches, fire extinguishers, and a current ignition source permit. The system tag.out was appropriate; however, operations personnel authorized shutting a pressure indicator isolation valve, 2SI-1043C, for valve repacking while the work crew was gone. This valve served as a drain valve for Valve 2SI-10C piping while the pressure indicator was removed. Closure of the valve prevented adequate venting of the system and caused water to spray in the contamination zone'when cutting to remove the valve began. The operations department did not inform the work crew that the valve was closed. The inspector considered authorizing a change to the position of Valve 2SI-1043C without notifying the work crew to be a weaknes Radiological controls during the valve replacement were good. A visit from the Radiation Protection /Radwaste Manager to the job site for assessment was indicative of strong management oversight. The radiography technicians and the examiners were qualified Level 2 and Level 1, respectively, for nondestructive examinations in accordance with Procedure 1415.019, Revision 3,
" Radiographic Examinations." The inspector confirmed that the technicians and
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-17-the examiners were trained, qualified, and certified by review of record The weld joints were acceptable and met the requirements for a satisfactory weld joint in accordance with the procedur .3 Unit 1 - Eighteen Month Inspection on Emergency Diesel Generator K-4A (JO 0091084)
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On September 20 the inspector observed a portion of an 18-month inspection on Emergency Diesel Generator K-4A in accordance with Procedure 1402.066, Revision 11, "18-Month Inspection on Unit 1 Emergency Diesel' Generator Engine." The maintenance and inspection of the lube oil system. involved the replacement of turbocharger lube oil Strainers F-52A and F-53A and the replacement of the lube oi , Equipment accountability was maintained by logging equipment into and out of the accountability area and taping down loose items worn by the mechanic The inspector observed inconsistencies with work personnel within the accountability area. At one time during the maintenance activity, a mechanic had his badge taped down for accountability purposes. Later on during the activity, the inspector noted that his badge was not taped. The inspector .i identified the loose badge to the licensee and the badge was subsequently taped down. The inspector reviewed Procedure 1025.019, Revision 5, " System Cleanliness Controls during Modification and Maintenance," and determined that a requirement to secure the badge was not specifie .4 Conclusions Maintenance activities observed were performed well and in accordance with' procedures. The presence of management at a worksite was indicative of stron i management oversight. The failure to alert workers to a valve position change was a weaknes BIMONTHLY SURVEILLANCE OBSERVATION (61726) 5.1 Unit 1 - Calibration of Waste Gas Instrumentation (JO 00894803) On August 23 the inspector observed a portion of the calibration of Waste Gas-Tank T-17 Level Transmitter LT-4812 per Procedure 1304.119,~" Unit 1 Waste Gas Surge Tank Instrument Calibration," Revision'4. The technicians appropriately followed the procedure and performed the task wel .2 Unit 1 - Local Leak Rate Testing of Personnel Hatch (JO 00898579) On August 23 local leak rate testing was performed on the Personnel Natch C-4 barrel. The technicians conducted the test in accordance with
'rocedure 1304.020,. Revision 8, " Unit 1 Reactor Building Access and Ventilation Leak Rate Testing." The leak rate values were well below the maximum acceptable values. The technicians were knowledgeable and performedL sound radiological work practice . _ _ _ _ _ _
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-18-5.3 Conclusions Observed surveillance activities were safely conducted in accordance with procedures. Instrumentation for the waste gas system was successfully calibrated and leak rate values for the personnel hatch were below the maximum acceptable limi '
6 REVIEW OF TEMPORARY INSTRUCTION 2500/028: " EMPLOYEE CONCERNS PROGRAM" (2500/028) 6.1 Units 1 and 2 Employee Concerns Program Survey Questionnaire The inspector interviewed the quality assurance coordinator with regards to a survey included in Temporary Instructions 2500/028, " Employee Concerns Program." The results are listed on Attachment ONSITE REVIEW 0F LICENSEE EVENT REPORTS (92700) (Closed) LER 368/91-006: " Core Protection Calculator Reactor Coolant System Flow Channels not Calibrated as Required by Technical Specifications due to Personnel Error" This LER reported the failure to calibrate the Core Protection Calculators (CPCs) as required by Technical Specification 3.3.1.1 Table 4.3-1, when the CPC indicated reactor coolant system flow was greater than the COLSS indicated reactor coolant system flow rate. New flow coefficient constants were calculated and entered into the CPCs, thus lowering the CPC indicated flow to less than COLSS indicated flow. Condition Report 2-91-094 was initiated and the root causa of the event was determined to be personnel error. The operations manager counseled the operators involved concerning log taking expectations. The operations manager also discussed the event during Requalification Training Cycle 90-04. Procedure 1015.003B, " Unit Two Operations Logs," was reviewed and Form 1015.003B-6, " Power Distribution And Burnup Log," was revised to include a column requiring operator initials for verification that CPC flow is less than or equal to COLSS flow. Based on the inspector's review of Condition Report 2-91-094 and Revision 36 to Procedure 1015.003B, all corrective actions have been complete .2 (Closed) LER 368/92-003: " Corrective Action for Reactor Coolant System Inventory loss via Letdown Relief Valve caused by a Cloqued Strainer Results in Subcritical Manual Reactor Trip"
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This LER reported a manual reactor trip in accordance wi'n Abnormal Operating Procedure 2203.016, " Excess RCS Leakage," due to abnorm 41 indications on the chemical and volume control system. Unit 2 was in Moda 3 Hot Standby with dilution to the reactor coolant system in progress when the trip was initiate It was determined that the source of the reactor coolant system l inventory loss was through Relief Valve 2PSV-4800 located on the letdown line at the inlet of the purification filters. High differential pressure across
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Letdown Strainer 2F-28, located downstream of Relief Valve 2PSV-4800 and ; between the purification ion exchangers and the volume control tank, caused ; Relief Valve 2PSV-4800 to exceed its pressure setpoint of 200 psig. Letdown flow was restored, normal flow was established, and Condition Report 2-92-0107 was initiate i System engineering performed an evaluation to determine the cause of high i differential pressure across the strainer; however, the root cause of the high ' differential pressure could not be positively determined. It was speculated , that small resin fines from the purification ion exchangers caused the elevated differential pressure. The strainer was blown down to reduce the , differential pressure while still in operation. No evidence of foreign i material was found during subsequent strainer replacement. Procedure i
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2203.012L, " Annunciator 2K12 Corrective Action," was revised to include a caution statement concerning high differential pressure across the letdown !
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strainer. Training was provided to the operational staff concerning lesson ; learned from the event. The licensee stated that high letdown strainer differential pressure has not been a recurring proble Condition Report 2-92-0107 also included an action to evaluate the need to l open the trip circuit breakers, which results in a manual reactor trip, during Mode 3 operations as required by Procedure 2203.016. Following a subsequent ! review of all Unit 2 abnormal operating procedures, Procedure 2203.016, Procedure 2203.036, " Loss of Charging," and Procedure 2203.038,." Primary to Secondary Leakage," were revised to delete the requirement to open the trip l circuit breakers during Modes 3, 4, or l
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Based on the inspector's review of Condition Report 2-92-107, k Procedures 2203.038, 2203.036, 2203.038, JO 00871621, Licensing Information Requests L92-0158, L92-0159, and Vendor Technical Manual Ll70.0010, all i corrective actions have been completed, j i
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1 PERSONS CONTACTED
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Licensee Personnel S. Bennett, Licensing Supervisor , S. Boncheff, Licensing Specialist
. S. Cotton, Radiation Protection and Radwaste Manager i D. Denton, Support Director '
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R. Edington, Unit 2 Plant Manager L. Humphrey, Quality Director R. King, Acting Licensing Director . R. Lane, Design Engineering Director W. McKelvy, Chemistry Supervisor J. Vandergrift, Unit 1 Plant Manager T. Weir, Materials, Purchasing, and Contracts Manager -{ The personnel listed a~c ove attended the exit meeting. In addition to the personnel listed above, the inspectors contacted other personnel during this inspection perio .;
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2 EXIT MEETING f An exit meeting was conducted on August 20, 1993. During this meeting, the inspectors reviewed the scope and findings of the report. The licensee did not identify as proprietary any information provided to, or reviewed by, the inspectors. The licensee acknowledged the inspection findings and did not , express a position on these finding { Postexit meetings were held with the Radiation Protection /Radwaste Manager on t October 13 and October 26, 1993, to further discuss licensee plans for prevention of posting failure ;
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EMPLOYEE CONCERNS PROGRAMS PLANT NAME: ARKANS AS NUCLEAR ONE LICENSEE: Enterev Operations DOCKET #: 50-313&50-368 PROGRAM: .
> Does the licensee, have an employee concems pmgram? l Yes j Has NRC inspected the program?
No
" SCOPE: (Circle all that apply) Is it for: Technical?
Yes
> Administrative?
Yes Personnel issues? , No. They would only be involved if these affected nuclear safet . Does it cover safety-as well as non-safety issues? Yes. All issues that come to the concerns coordinator are investigate Nonsafety and personnel issues are referred to Human Resources for - further actio . Is it designed for:
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' Nuclear safety?
Yes i Personal safety? No. Industrial Safety would handle proble Personnel issues - including union grievances?
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' Does the program apply to all licensee employees?- !
Yes .;
' Contractors?
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Yes . Does the licensee require its contractors and their subs to have a similar ,
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program? No. Contractors on site are directed to use ANO's progra ; Does the licensee conduct an exit interview upon terminating employees asking - if they have any safety concerns? : Yes, and it also applies to contractor , C. INDEPENDENCE: What is the title of the person in charge? .j QA Supervisor Who do they report to? q Director of Quality
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Yes
! Does the ECP use thirti party consultants?
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Yes. QA personnel and other inhouse organizations perform some investigations, but no outside consultants are use , now is a concern about a manager or vice president followed up? a The same process would be use :
, RESOURCES:
1 What is the size of the staff devoted to this pmgram? One person, with the ability to call on additionalinhouse support when ( neede ! j i
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There is no formal training progra REFERRALS:
. Who has followup on concerns (ECP staff, line management, other)?
Follow up is performed by concerns coordinator including evaluation of - corrective actions (when required) through closecu CONFIDENTIALITY: Are the repons confidential? Yes To whom is the identity of the alleger made known? Senior management Can employees be: Anonymous? - Yes Report by phone? Yes G. FEEDBACK: Is feedback given to the alleger upon completion of the followup? Yes, when a response is requested by an alleger, the results are provided by the licensee by mail or by phone as desire . Does pmgram reward good ideas? N/A Who, or at what level, makes the final decision of resolution? Concerns Coordinator (QA Supervisor) with the Director of Qualit . , .
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Yes, all are treated as concern , Are resolutions of valid concerns publicized (newsletter, bulletin board, all hands meeting, other)? ;
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No
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II. EFFECTIVENESS: How does the licensee measure the effectiveness of the progam? It is included in biennial audit of Quality Organizatio , f Are concerns: Trended? Yes Used? Yes. An example is Procedure and Directive have been strengthened for lessons learne ; In the last three years how many concerns were mised? 10 of the concerns raised, how may were closed? 3 What percentage were , substantiated? 0 There was no impact on the plant, however, discrepancies were discovered and corrected appropriatel . How ate followup techniques used to measure effectiveness? By the use of a random survey How frequently am internal audits of the ECP conducted and by whom? r Every other year by corporate Quality Organizatio ! i
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Yes, Station Directive A2.205, Revision 3, " Nuclear Safety / Quality Concerns" and QA Operating Procedure QAO-12, Revision 1, j
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" Notification / Processing of Safety Quality Concerns in Nuclea ,
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' How are employees, as well as contractors, made aware of this program?
By training and a bulletin board , t i NAME: TITLE: PIIONE #: S. J. Campbell / Resident Inspector /501-968-3290 DATE COMPLETED: 08/26/93 , m. }}