IR 05000259/1994018
| ML18038A868 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 08/25/1994 |
| From: | Lesser M, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038A867 | List: |
| References | |
| 50-259-94-18, 50-260-94-18, 50-296-94-18, NUDOCS 9409070010 | |
| Download: ML18038A868 (42) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 303234199 Report Nos.:
50-259/94-18, 50-260/94-18, and 50-296/94-18 Licensee:
Tennessee Valley Autho}ity 6N 38A Lookout Place 1101 Harket Street Chattanooga, TN 37402-2801 Docket Nos.:
50-259, 50-260, and 50-296 License Nos.:
DPR-33, DPR-52, and DPR-68 Facility Name:
Browns Ferry Units 1, 2, and
Inspection at Browns Ferry Site near Decatur, Alabama Inspection Conducted:
July 17 August 13, 1994 Inspector:
e nar
.
ert r.,
en>or es1 ent nspector ate s
ne Accompanied by:
J.
Hunday, Resident Inspector R. Husser, Resident Inspector G. Schnebli, Resident Inspector J. York, Project Engineer Approved by:
ar
.
esser, ctsng rane le Reactor Projects, Branch
Division of Reactor Projects ate cygne SUHHARY Scope:
This routine resident inspection involved inspection on-site in the areas of operations, surveillance testing, maintenance activities, plant support activities including the annual emergency preparedness drill, drywell 0-ring issues, Unit 3 recovery actions, and review of open items.
A detailed inspection of containment coatings was also performed.
Additionally, meetings were held with local officials and the local public document room was visited.
Several hours of backshift coverage were routinely worked during most work weeks.
Deep backshift inspections were conducted on July 20, 24, 25, 29, and
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30.
9409070010
'3I40EI25 PDR ADOCK 05000259
PDR,,
Results:
One non-cited violation and one inspector followup item were identified:
The non-cited violation addressed inadequate corrective actions involving 0-rings installed in the Unit 2 drywell hatches.
The licensee identified that some of the.0-rings were of an incorrect material.
The deficiencies had been caused'y inadequate corrective actions in 1973.
The inspectors noted that the determination of which installed 0-rings were actually of the incorrect material was delayed.
The delays were apparently related to materials records.
(NCV 260/94-18-01:
Inadequate Corrective Actions for Improper Drywell 0-ring Haterial, paragraph 6.)
The inspector followup item addressed several issues involving unqualified coatings in the Unit 3 containment.
The licensee has developed corrective actions to be completed prior to the restart of the unit.
The inspectors concluded that overall cont'rol of containment coatings at Browns Ferry is adequate.
{IFI 296/94-18-02:
Condition of Unit 3 Containment Coatings, paragraph 8.)
In the area of operations, the inspectors noted several examples of less than appropriate attention regarding overall housekeeping and material conditions in areas of the plant apparently not frequently toured.
No operability or significant fire protection issues were identified.
The concerns included deficiencies on the top of the Unit 2 torus and in a Unit 1 residual heat removal system compartment.
{Paragraph 2b.)
Two concerns were identified by the inspectors involving technical operability evaluations.
In one instance, the operability conclusions were not adequately supported by the information provided in the evaluation.
In another case, operations personnel were not prepared to complete actions which were listed in the evaluation.
The formal operability procedure is a recent development and is considered an enhancement.
(Paragraph 2c.)
In the area of plant support, the annual emergency planning exercise was conducted on July 20.
Several of the inspectors evaluated the drill while two other inspectors participated.
No significant deficiencies were noted and it was concluded that the drill successfully met its objectives.
(Paragraph 5a.)
REPORT DETAILS Persons Contacted Licensee Employees:
T. Abney, Technical Support Manager J. Brazell, Site Security Manager D. Burrell, Acting Engineering and Materials Manager J.
Corey, Radiological Control Manager
- T. Cornelius, Emergency Preparedness Manager C. Crane, Business and Work Performance Manager J. Johnson, guality Assurance Manager R. Jones, Operations Superintendent R. Hachon, Site Vice President, Browns Ferry
- J. Haddox, Maintenance and Modification Hanager
- R. Moll, Plant Operations Manager
- E. Preston, Plant Manager
- S. Rudge, Site Support Hanager P. Salas, Licensing Manager T. Shriver, Licensing and guality Assurance Manager A. Sorrell, Chemistry and Radiological Controls Manager D. Stinson, Recovery Manager R. Wells, Compliance Manager Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, public safety officers, and quality assurance, design, and engineering personnel.
NRC Personnel:
- L. Wert, Senior Resident Inspector
- J. Munday, Resident Inspector R. Husser, Resident Inspector
- G. Schnebli, Resident Inspector J York, Project Engineer
- Attended exit interview NRC Management Site Visits:
H. Lesser, Section Chief Acronyms and initialisms used throughout this report are listed in the last paragrap Plant Operations (71707)
(92901)
(40500)
Operations Status and Observations Unit 2 operated at power this period without any significant problems.
At the end of the period the unit had been continuously
.on-line for 115 days.
End of cycle coastdown began in July.
On August 6, 1994 power was reduced to approximately 70X for scram time testing and BOP maintenance.
On August 11, power was in-creased and final feedwater temperature reduction was implemented.
Recovery activities continued on Unit 3.
Unit 1 remained in layup conditions.
Activities within the control rooms were monitored routinely.
Inspections were conducted on day and night shifts, during week-days and on weekends.
Observations included control room manning, access control,'perator professionalism and attentiveness, and adherence to procedures.
The inspectors noted that operators were cognizant of plant conditions and were attentive in their duties.
Instrument readings, recorder traces, annunciator alarms, opera-bility of nuclear instrumentation and reactor protection system channels, availability of power sources, and oper ability of the Safety Parameter Display System were monitored.
Unit I/2 control room observations also included ECCS system lineups, primary and secondary containment integrity, reactor mode switch position, scram discharge volume valve positions, and rod movement controls.
Observations in the Unit 3 control room were more limited in scope and focused on major activities in progress and operable systems.
Several clearances were verified as being correctly implemented.
Paragraph 2f discusses a detailed inspec-tion of a complex clearance.
Daily discussions were held with plant management and various members of the plant operating staff.
One of the inspectors attended the daily Plan of the Day meetings.
Plant tours were taken throughout the reporting period on a routine basis.
Obser-vations included valve position and system alignment, snubber and hanger conditions, containment isolation alignments, instrument readings, housekeeping, power supply and breaker alignments, radiation and contaminated area controls, tag controls on equip-ment, work activities in progress, and radiological protection controls.
Informal discussions were held with plant personnel during these tours. Additionally, the inspectors accompanied some auxiliary unit operators on their rounds.
Personnel were very attentive regarding the specific equipment checks required by the procedures.
The tours in the Unit 1 areas focused on maintenance activities and systems required to be operable.
Emphasis was placed on control of maintenance activities during the Unit 3 tours.
Paragraph 2b contains discussion of issues noted during some tour Plant Tour Observations During the report period, the inspectors noted several examples of less than appropriate attention regarding overall housekeeping and material conditions in areas of the plant not frequently toured.
In early July, one of the inspectors noted several problems in the Unit
RHR system II compartment.
This system is required by TS to support Unit 2 operations.
Numerous small tools and articles of trash were noted on the floors.
Scaffolding which had expired over a year ago and insufficient lighting was noted on one eleva-tion.
In general, it was noted that the compartment was not being monitored to the standards of the Unit 2 equipment spaces.
No operability issues or significant fire protection issues were noted.
The compartment is not included in the "housekeeping program".
The concerns were discussed with site management.
On August 3, the inspectors toured the room and noted that the deficiencies had been corrected.
During a routine tour, one of the inspectors noted elevated temperatures in the 3ED diesel generator room.
The inspector identified that the room heater was running with its thermostat set at above 90 degrees F.
This situation was reported to onshift operations personnel and was promptly corrected.
On July 19, the inspectors performed a walkdown of the area on top of the Unit 2 torus.
The area was marked off as a contaminated zone and had elevated temperatures.
The overall housekeeping and cleanliness conditions were satisfactory, however, the inspectors identified several items of concern.
The first concern was a small leak dripping through insulation on the RHR loop II injection line.
The injection line runs up through the ceiling above the torus and enters the clean room located on the 565 foot elevation in the reactor building.
The inspectors noted water leaking through the pipe insulation at the point where the pipe penetrated the ceiling.
The water was captured in a funnel and routed to the floor drain.
Discussion with the operators on duty about the source of the leak indicated that they were unaware that a leak existed in that area.
After removal of some insulation and additional review, the licensee determined that the leak was coming from the 2-FCV-74-66, RHR loop II outboard injection valve.
This leak had been previously identified and scheduled for repair during the upcoming refueling outage.
The inspectors verified that the repair was listed on the outage list.
The inspectors identified that an electrical junction box, 2JB-074-2310, was not properly sealed.
The inspectors identified that the box provided a connection point for cables associated with Eg components.
In addition, during a subsequent inspection, the inspector identified another junction box located on the 519 foot
elevation in the RHR loop II pump room which was improperly sealed.
Subsequently, it was determined that these boxes are intended to be sealed not because of Eg concerns but rather to prevent moisture from spray of the fire protection system or humidity from entering.
The licensee initiated BFPER940421 to document the problem and identify actions to ensure these boxes as
,well as others similar to this are properly sealed.
The PER stated that the purpose of the box was to provide structural support and electrical separation from other electrical divisions.
It stated that the absence of the seal did not result in the loss of this function and therefore the operability of the cables inside was unaffected.
Although it was not discussed in the PER, weep holes existed in the bottom of the boxes to ensure that any moisture that may enter does not collect but rather is drained off.
On subsequent plant tours the inspectors identified three addi-tional junction boxes which did not have weep holes drilled in the bottom.
Haintenance was informed and WOs were generated to facilitate repairs.
BFPER940512 was initiated to address the fact that the holes were not present despite clear requirements for the holes on drawings.
Operability was not affected by the missing weep holes.
The inspectors concluded that these issues, although not of large safety significance, indicate that more attention to detail is necessary regarding areas of the plant not frequently toured.
Technical Operability Evaluation Issues In Harch 1994, the licensee implemented TI 313:
Engineering Evaluations for Operability Determination.
The procedure general-ly follows the guidance in GL 91-18 regarding operability deci-sions.
The output of this procedure is a Technical Operability Evaluation.
While the development of the procedure to formalize the operability determination process is seen as an enhancement, the inspectors have identified problems involving two recent TOEs.
On July 1, 1994 TOE 2-94-064-0089 was completed.
The TOE ad-dressed the licensee's identification that 0-rings installed in several of the Unit 2 drywell hatches were of an improper materi-al.
(Paragraph 6 of this report discusses this issue.)
The licensee promptly communicated the concern to the inspectors.
The inspectors reviewed the TOE which concluded that the 0-rings were operable because the silicon material would not be exposed to radiation levels above the damage threshold.
The inspectors noted that the evaluation relied on the application of multiplication factors from the source term of GE Topical Report APED 5756.
This resulted in lower dose rates than those projected if the TID-14844 source term were directly applied.
The inspectors transmitted the TOE to NRR for technical assistance regarding the acceptance of the licensee's evaluation.
A telephone call was conducted involv-
ing Region II management, the NRR project manager and technical reviewers, the inspectors, and the licensee.
It was concluded that additional information was necessary to fully support the operability of the 0-rings.
On July 29, the inspectors were provided an updated TOE.
The TOE more fully explained the assump-tions utilized in the evaluation and provided additional justifi-cation that the 0-rings were operable.
The inspector reviewed BFPER940337 which documented a concern with a flood drain line in the unit I/2 DG building.
The PER stated that it was possible that a single check valve failure could render the flood protection for two trains of DGs incapable of performing their intended function.
TOE 0-94-040-0337 was issued which addressed actions that were required should a pipe inside the building break and a flood condition occur.
Specifically, the TOE stated that in the event that building sump high level alarms are received, personnel are to be dispatched and be prepared to open the DG building doors or to manually start the sump pumps.
In addition, it stated that if maintenance is being performed on any water systems in the buildings, an operator should be sta-tioned in the building or a door opened to protect against inter-nal flooding.
On July 18, 1994, the inspector questioned opera-tors on duty in the control room about these actions and they were unaware of the concern or the requirements of the TOE.
This was brought to the attention of Operations management and subsequently Operations Standing Order OS-0086 was issued describing the appropriate actions to take.
The inspectors questioned how requirements delineated in TOEs are disseminated to the people responsible for the actions.
Licensee management responded by emphasizing that the section managers signing the TOEs will be held responsible to ensure any required compensatory measures are taken.
In both of the above examples, the inspectors did not conclude that the associated equipment was inoperable.
The operability conclusions were not adequately supported by the information provided in the TOE.
In the case of the diesel generator building flooding issue, the reviews by operations personnel were not sufficiently detailed.
The inspectors recognize that in some cases, an initial operability decision may be made with additional information pending.
Completion of a TOE or operability decision is expected to be made once sufficient information is available and consistent with GL 91-18.
The licensee addressed the above concerns appropriately.
Leak on Unit 2 RFP Minimum Flow Line On July 25, 1994, a leak was discovered on the 2B RFP minimum flow line in the feed pump room.
The leak was at an elbow in the minimum flow line back to the main condenser downstream of flow control valve 2-FCV-3-13.
The licensee documented the problem in BFPER940448 and took prompt corrective actions to contain the
leakage.
Corrective actions included closing a downstream manual isolation valve (3-516), increasing air pressure to the operator on the flow control valve to seat the valve tighter, and the installation of a clamp type patch over the leaking area.
In addition, the licensee roped off the area for personnel protec-tion; These temporary measures will remain in effect until
.permanent repairs are made during the upcomming Unit 2 outage in October 1994.
The licensee also performed UT examinations on the piping and determined that the elbow had an eroded area of approx-imately 6 inches wide by 12 inches long.
Similar areas for 2A and 2C RFPs were also tested and showed only minimal evidence of erosion.
The licensee determined the cause of erosion was leakage by the flow control valve.
At the close of this inspection report, the licensee was still reviewing issues involving the air pressure supplied to the valve operator.
The piping was not in the licensee's Erosion-Corrosion Monitoring Program as these lines do not normally'ontain steam flow during normal operation as they are isolated.
The residents will continue to follow this issue until repairs are complete.
Unit 2 Cycle 7 Final Feedwater Temperature Reduction On August 9, 1994, while at reduced power, the licensee isolated the last stage high pressure feedwater heaters to reduce the final feedwater temperature and increase reactor power and electrical generation.
This mode of operation is referred to as Final Feedwater Temperature Reduction and is used primarily to extend full power capability at the end of the operating cycle.
The inspectors reviewed the licensee's procedural controls and analy-ses for this operation.
General Electric provided an analysis for operation with a 47 degree reduction in final feedwater tempera-ture which corresponds to 330 degrees F.
The licensee performed a
safety evaluation for this operation and determined that an unreviewed safety question did not exist.
An additional reduction of 10 degrees F was allowed for uncertainty in the feedwater measurement.
The SE stated that intentional continuous operation with a temperature reduction greater than 47 degrees F was not justified and the feedwater temperature should be brought within the analyzed band.
The inspector reviewed both the GE analysis and the SE.
In addition, the inspectors reviewed 2-0I-6, Feedwat-er Heating And Miscellaneous Drains System, revision 19, which controls the process of isolating the feedwater heaters and establishing the reduced feedwater temperature.
The inspectors noted that the procedure ensured the final feedwater temperature was within the allowable region of the FFTR graph, however, the allowable region included the 10 degrees F reserved for uncertain-ty.
Therefore the graph allowed operation with a final feedwater temperature of 320 degrees F.
This was brought to the attention of Operations management who agreed with the inspectors assessment and stated that the procedure would be revised.
During a subse
quent discussion Operations management stated that this discrepan-cy had been previously identified by the Operations staff and was in the process of being corrected.
The inspectors observed the implementation of some of the feedwat-er heating reduction.
It was noted that the plant parameters matched very closely to values in the analysis.
Although some problems involving feedwater heater level control were encoun-tered, the inspectors concluded that the licensee's preparations for FFTR were appropriate.
Clearance Walkdown During this report period the inspector performed a walkdown of clearance 0-94-0198.
This clearance is a caution order written as a result of electrical load limitations imposed by DCN S16651.
The DCN documents restrictions on plant loads which could adverse-ly affect Unit 2 safe shutdown capability.
The caution tags reference various plant procedures which contain instructions needed to operate the component tagged.
Typically the procedure referenced will identify a drawing which in turn is annotated to include various limitations on the individual loads.
The inspec-tor verified the tags were in place and the clearance forms appropriately completed.
Several components were selected to verify that the appropriate conditions were met for the component to be aligned as it was found.
Breakers 201 and 215 located on 250 VDC distribution board 3 were found in the closed position.
The appropriate procedure, O-OI-57D, and drawing, 3-45E707, were referenced which contained a note that stated these two breakers could not simultaneously provide power at any time.
Operations management was informed of this condition and subsequently deter-mined that while the two breakers were closed, neither was actual-ly energized.
One of the circuits contained a knife switch in series with the breaker which was opened.
The knife switch was not tagged by this clearance, however, Operations management stated oper ation of this switch would result in a main generator trip and as such was not operated at power.
Operations later added the switch to the caution order.
The other circuit also contained an additional switch.
The switch was a spring return type with no position indication and the state of the circuit could not be determined.
The switch was tagged by clearance 0-94-197 which requires the same verifications as clearance 0-94-0198.
Additional loads were verified to be aligned in accordance with the plant drawings.
While the clearance is complex and difficult to use, no significant problems were identified.
3.
Surveillance Testing (61726, 92901)
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Surveillance Observations
e Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy.
The completed tests reviewed were examined for necessary test prerequisites, instructions, acceptance criteria, technical content, authorization to begin work, data collection, independent verification where required, handling of deficiencies noted, and review of completed work.
The tests witnessed, in whole or in part, were inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and systems restoration was completed.
The following surveillances were specifically reviewed and wit-nessed in whole or in part:
l.
2-SI-4.2.8-27FT HPCI Suppression Chamber High Level Instrumentation Functional Test.
2.
2-SI-2 Instrument Checks and Observations 3.
2-SI-4.3.C Scram Insertion Times b.
During the observations, the inspectors noted that procedures were consistently utilized and communications appeared strong.
The proficiency observed during some of the testing indicated that detailed preparation had been conducted prior to the work.
Control Rod Failure to Scram During Testing On August 8, 1994 while performing 2-SI-4.3.C, Scram Insertion Times, control rod 30-15 failed to insert when given a scram signal.
The problem was determined to be a failure of the scram pilot solenoid valve, 2-FSV-085-39B-3015.
When the solenoid was deenergized the valve did not change position as designed.
Operations inserted the rod to the full in position with the normal rod movement switch and electrically disarmed the control amphenols and placed them under clearance.
The inspectors ob-served portions of these actions in progress.
WO 94-12541-00 was written to replace the solenoid valve.
Following installation, the new valve was tested by successfully scramming the control rod.
The failed valve was disassembled and inspected by the licensee and the inspectors.
The inspectors noted a slight amount of drag as the core was exercised in the solenoid base sub-assembly.
No additional abnormalities were noted at this time.
After reassem-bling, the valve was energized and allowed to heat up to normal operating temperature.
It was then deenergized and reenergized three times and the core repositioned successfully each time.
However, the fourth time the coil was deenergized, the core did not reposition.
Following disassembly the core still remained in the energized position.
A slight sideways force exerted on the
top of the core caused it to release and move.
A closer inspec-tion revealed two small bumps on the inner wall of the sub-assem-bly with corresponding indentions on the outer wall.
The inden-tions were similar to what one would see if the sub-assembly were crimped with pliers.
It was not readily apparent that this was the cause of the core not repositioning however no other abnormal-ities were noted.
The licensee is continuing review of the failure.
GE has also been involved in the review.
The inspector's review of maintenance records indicated that the valve had been rebuilt during the Unit 2 cycle 6 refueling outage under WO 92-64836-00.
Following the rebuild the rod was success-fu'lly scrammed as a
PMT prior to the unit starting up from the outage.
In the event of an actual scram, the backup scram valves would actuate and scram the rod.
The inspector requested control rod scram data from the April 15, 1994 scram to attempt to deter-mine if this valve had actuated then, however the information could not be obtained.
The licensee stated that the system is designed to collect scram time data, however it has not yet been made operational.
At the close of this inspection period, the licensee's investiga-tion into the failure was still in progress.
The failure appeared to be an isolated case.
Initial information indicated that the failure mechanism was different from those involved in the majori-ty of previous solenoid valve failures in the industry.
No violations or deviations were identified.
Maintenance Activities (62703, 92902)
Maintenance activities were observed and/or reviewed during the report-ing period to verify that work was performed by qualified personnel and that approved procedures in use adequately described work that was not within the skill of the trade.
Activities, procedures, and work requests were examined to verify proper authorization to begin work, provisions for fire hazards, cleanliness, exposure control, proper return of equipment to service, and that limiting conditions for operation were met.
The following maintenance activities were reviewed and witnessed in whole or in part:
1.
WO 94-10011 2.
WO 94-12541 RHRSW Pump Al Replacement Replacement of Scram Pilot Solenoid Valve 2-FSV-085-0398-3015 Paragraph 7 of this report contains additional observations in the maintenance are On July 25, 1994, the licensee tagged out RHRSW pump Al for the purpose of replacing the pump and cleaning out the RHRSW/EECW pit at the plant intake structure.
The pump was being replaced as it was exhibiting an increase in vibration.
The work was to be performed in accordance with WO 94-10011.
The inspector observed the removal of portions the deep draft pump sections.
After removal of the pump, the inspector examined the impeller and pump section and noted that they were in an acceptable
'condition.
Following removal of the pump, the licensee introduced a robot into the service water pit for the purpose visually inspecting and vacuuming debris (shells and silt).
This effort did not prove successful as the mobility of the robot was limited.
A few days later, a diver entered the pit in order to "map out" the debris in the pit.
The licensee determined that the condition of the pit was acceptable for reinstalla-tion of the pump.
The licensee is currently developing formal accep-tance criteria for the amount of debris that is acceptable for pump operability.
The licensee stated that they would brief the inspectors on the development of this criteria.
In addition, the inspector veri-fied proper installation and adequacy of hold order (clearance)
0-94-0468 for this maintenance item.
The inspectors will continue to monitor the licensee's effort in developing a program for cleaning and monitor-ing the intake service water pit.
No violations or deviations were identified.
Plant Support (71750, 92904)
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Observation of EP Exercise On July 21, 1994, the inspectors observed the annual Browns Ferry emergency preparedness exercise.
Two of the inspectors partici-pated in the drill, one in the Technical Support Center and one in the simulator.
Two other inspectors evaluated the drill.
A Region II based inspector evaluated the drill in the Central Emergency Control Center located in Chattanooga.
Two inspectors also attended the licensee's critique session.
During the drill the inspectors made several observations which were discussed with licensee management.
The inspectors observed that there were numerous calls to the control room, from people both inside and outside the plant, requesting the status at the beginning of the drill.
This had a
tendency to distract the control room personnel.
The licensee was reviewing this issue for corrective actions.
The inspectors noted that since the drill, an actual medical emergency occurred in the plant and there were no phone calls to the CR in that case.
The inspectors noted several areas in which procedures should be reviewed for potential improvements.
In response to the comments, operations management verified that some of the involved proce-
dures did contain the appropriate guidance.
At the close of the report period, the licensee was reviewing procedural controls on bypassing the high drywell pressure interlock on RHR.
There was a slight delay in the formal declaration of escalation to a Site Area Emergency.
The delay was not excessive and ap-peared to be caused by discussions between the TSC and CECC about the escalation.
The inspectors at the site noted that the CECC discussed the potential use of the hardened vent to relieve a small amount of drywell pressure.
The emergency director indicated that he did not consider this as an option.
Additionally, the inspectors noted that CR personnel also indicated that they did not regard this as an option.
One inspector observed the activation, staffing, and operation of the Emergency Response Organization that responded to the Central Emergency Control Center.
The CECC director and his staff were effective in performing required functions.
Because the simulated accident did not progress to a General Emergency with a potential or actual radiological release there was no requirement for protective action recommendations to be made.
The CECC communica-tions staff was effective in demonstrating the ability to develop timely and accurate news releases.
Several strengths were noted.
The organization and setup of the TSC before the emergency director's arrival was good.
The inspec-tors noted that the participants were very professional in their participation in the drill. Additionally, good command and control was exhibited in the OSC.
Overall, the drill was successfully executed and met its objec-tives.
Digital Alarming Dosimetry Devices During routine tours of the facility early in the report period, the inspectors noted that a number of workers appeared to be wearing their DADs improperly.
In several instances, the devices were not located on the front of the wearer (for example in the back pants pocket).
In some cases, the device was not facing forward.
These observations were discussed with the radiological controls manager.
The licensee performed some review of dosimetry wearing practices and issued a notice clarifying the requirements for DAD placement.
The inspectors have noted that the notices have been prominently displayed throughout the plant.
No other instances of improper DAD locations have been noted.
On August 2, 1994, one of the inspectors noted three DADs in the dosimeter storage racks with indicated dose still existing.
DADs are returned to these racks after they are used and the dose
recorded on the DAD is logged into the REX system via computer terminals.
The indicated dose is usually erased by the REX system and replaced with the word "PAUSE". It is then ready for another use.
The inspector questioned Radcon about the three DADS still indicating dose and was told that occasionally the indicated dose would remain on the DAD after it has been logged into the REX system if it was removed from the terminal prematurely.
The technician stated that there would be no effect on the dose records of the user.
The inspector requested Radcon to attempt to log the DAD in and verify the dose record was unaffected.
When this was attempted, the DADs logged in normally as though the users failed to do so upon exiting the RCA.
A computer search of the uses of the DAD indicated that the DAD had in fact been logged in by the user and again by Radcon without the DAD having been logged back out first.
The inspector questioned Radcon if the individual was assessed with the dose indicated on the DAD twice and was informe'd that the DAD had indicated no dose.
Another search indicated that another user had been allowed to log out two DADs simultaneously.
Radcon and the inspector checked the storage racks for additional DADs indicating dose and two more were identified.
The inspector informed the radiological controls manager of these discrepancies.
BFPER940494 was initiated to address these discrepancies.
At the close of this report, the licensee was investigating these issues.
The inspectors will continue to monitor the licensee's actions.
1A Raw Cooling Water Booster Pump Transportation On July 15, a small amount of radioactive contamination was found inside the end bells of the 1A RCW booster pump which had been transported as radiologically clean material to the TVA Muscle Shoals Power Service Shop for maintenance.
The issue was reported to the inspectors by the BFN manager of radiological controls.
The motor had been removed from an uncontaminated area in the Unit 1 reactor building with the end bells installed.
Some checks for contamination had been performed by reaching as far up as possible inside the end bells and no activity was found.
A decision was made that the motor could be transported as not contaminated.
The inspectors reviewed a statement on the incident written by a Huscle Shoals health physics technician.
The technician noted that workers had donned gloves prior to starting work and the end bells were checked immediately upon removal from the motor.
Levels as high as 3000 dpm/100 cm squared were identified.
(Levels in excess of 1000 dpm are not transported as clean equipment out of BFN.)
The equipment was immediately moved to an area in which radioactive materials are handled and work was halted.
The inspectors were informed that the PSS does perform maintenance on contaminated equipment but only with workers specifically trained for such work.
The inspectors also reviewed a statement written by the health physics technician who decided that the motor could be transported without removing the end bells to check for contam-ination.
RCI 1. 1 requires that components suspected of internal
contamination be disassembled and surveyed but the requirement can be waived with the approval of the RCSS.
Apparently, a factor in his decision was his understanding that the motor had recently been sent to the PSS for maintenance.
The licensee's investiga-tion indicated that other maintenance problems contributed to the event.
In response to the inspectors questions, the licensee-stated that the motor had been transported unwrapped and untagged in the open end of a truck.
Additionally, the licensee stated that the Huscle Shoals PSS routinely checks for contamination on such equipment upon arrival from BFN.
After review of the issue and discussion with the NRC regional health physics management, the inspectors concluded that the safety significance of the issue was small.
The level of contami-nation was very low.
Given the specifics of this incident, it was improbable that the contamination could have been inadvertently spread.
The inspectors noted that the apparent thoroughness of the Huscle Shoals workers played an important role in reducing the significance of this issue.
A review of the event was performed and was documented in RAR 94-010.
The RAR discussed similar events which have occurred previously.
The inspector reviewed those items and concluded that those events were not clear exam-ples of inappropriately released material.
At the close of this report period, the licensee's corrective actions were still being finalized but more thorough checks of any equipment leaving the RCA (instead of "suspected of internal contamination")
are being considered.
The licensee polled other Region II facilities in order to assess if their controls had been less rigid than other facilities.
Approximately half of the other facilities stated that they would have transported such equipment without removing the end bells to check for contamination.
The inspectors will continue to follow the licensee's corrective actions.
Additionally, the issue will be reviewed by regional health physics inspectors.
No violations or deviations were identified.
Drywell 0-rings Issue (37551, 40500, 92903)
(Unit 2)
Early on July 18, 1994, the inspectors were informed of a problem involving the 0-rings installed in the various drywell penetrations (equipment hatches, DW head, CRD latch, manways, and other penetra-tions).
The overall issue is that the 0-rings are made of silicone rubber.
In 1972, a decision had been made that, due to concerns involving post integrated doses, the 0-rings should be made of Nordel.
Nordel is the trade name for ethylene-propylene rubber which has a
higher radiation damage threshold than silicone.
On April 21, 1994, PER 2-94-064-0089 was initiated due to questioning by an individual in the licensee's gA department.
The individual had been
reading about 0-ring issues and reviewed details of the Unit 2 drywell hatch 0-ring installation.
It was determined that the existing TVA controlled design drawing listed silicone as the material for the DW hatch 0-ring.
Reviews had indicated that in 1972 a commitment had been made to the NRC to remove silicone rubber from the design drawing.
Additionally, in 1973, the NRC had cited the licensee (IR 50-259/73-13)
for using silicone rubber 0-rings on the Unit
DW head after the commitment.
Additional review determined that the 0-rings actually installed on the DW hatch were Nordel.
At that time the issue appeared to be limited to a process problem, with no potential operability issues.
Corrective action D.8.5 (due September 16, 1994) for the PER required that the other 0-rings in the drywell be verified as of the proper material.
On June 30, 1994, it was determined that some of the installed 0-rings (other than the DW head)
were silicone.
Silicone 0-rings were also found in stock.
A TOE was completed on July 1, 1994, which reviewed the effect of the incorrect 0-ring material.
Revision 1 to PER 94-0089 was written on July 14, 1994, to address the installation of incorrect material O-rings.
The inspectors reviewed the issue including the TOE and several of the referenced documents.
The licensee provided additional details and responded to inspector's questions.
The TOE relied upon use of the source term and assumptions in GE Topical Report APED 5756 for calcula-tions of radiation exposure.
This source term is compared to the Total Integrated Dose (TID-14844) source term in Section 14.9 of the BF FSAR and is regarded by the licensee as a "more realistic" source term.
Paragraph 2c of this reports addresses issues involving this TOE.
The inspectors concluded that the primary concern with this issue is the inadequate corrective actions which resulted in the incorrect 0-rings being installed.
Drawings were not revised to indicate the proper material.
Procurement processes had not been changed such that only Nordel 0-rings were purchased.
These actions were stated in response to a NOV dated October 1973.
The failure to implement effective corrective actions is a violation of Criterion XVI of Appendix B of 10 CFR 50.
This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the Enforce-ment Policy.
The violation was not willful. It was identified through
'uestioning and reviews by licensee personnel.
It did not result in any safety systems being inoperable or significantly degraded.
The viola-tion was a result of inadequate corrective actions which occurred over twenty years ago.
The licensee is in the process of implementing actions to ensure that the improper 0-rings which are available in storage will not be installed in the plant.
Additional measures to prevent recurrence are being developed.
This item is identified as NCV 50-260/94-18-01:
Inadequate Corrective Actions For Improper Drywell 0-ring Hateria During their review of this issue, the inspectors noted two other related concerns:
It required approximately one month for the licensee to determine what material 0-rings were actually installed in the plant.
These 0-rings had been installed in recent years.
Apparently, difficulties involving materials/procurement records resulted in the delay.
A 1993 PEG package had downgraded the 0-rings from QA level II to QA level III.
In general, items which are considered to perform a safety related function or could prevent a component from performing its safety related function, are classified as QA level II (commercial, dedicated).
The inspectors, noting that the licensee has identified other such issues, requested that the basis and acceptability of this decision be reviewed.
At the close of the report period, the licensee's QA group was completing an audit in the materials area and the QA III/IIissues were being examined.
One NCV was identified.
Unit 3 Restart Activities (37828, 61726, 62703, 37550, 92903)
(Unit 3)
The inspector reviewed and observed the licensee's activities involved with the Unit 3 restart.
This included reviews of procedures, post-job activities, and completed field work; observation of pre-job field work, in-progress field work, and QA/QC activities; attendance at restart progress meetings, and management meetings; and periodic discussions with both TVA and contractor personnel, skilled craftsmen, supervisors, and managers.
a ~
Design Changes and Plant Modifications The inspectors reviewed selected DCN packages associated with plant modifications to support the Unit 3 recovery effort.
The DCN work packages were reviewed and work in progress was observed to:
ensure that the DCN packages were properly reviewed and approved by the appropriate organizations in accordance with the licensees administrative controls; verify the adequacy of the
CFR 50.59 evaluations performed and that the appropriate FSAR revisions were planned or completed, if applicable; ensure that the applicable plant operating procedures and design documents were identified and revised to reflect the modification; verify that the modifications were reviewed and incorporated into the operations training program, as applicable; verify that the modifications were installed in accordance with the work package (for those that could be physically inspected);
ensure that the modification was consistent with applicable codes and standards, regulatory requirements, and licensee commitments; and ensure that
post modification testing requirements were specified and that adequate testing was accomplished.
The following modifications were reviewed in detail:
DCN No.
17702A, Replacement of Unit 3 Shutdown Board Room Chillers
. This modification replaced the Unit 3 Shutdown Board Room Emergen-cy Cooling units with new units.
The old ACUs were standard 5-ton commercial grade systems that were not qualified for operation within the expected Reactor Building post-accident harsh environ-ment.
The new units are two 25-ton, redundant, 100X-capacity units, powered from Class lE circuits with the diesel generators as a back-up power source.
The new ACUs are designed to maintain the temperature in the safety related Shutdown Board Rooms below the maximum steady state temperature of 104 degrees F during normal operating conditions in Units 1 and 2 with a simultaneous LOCA accident condition in Unit 3.
The inspectors reviewed the DCN and associated Safety Assessment (SABFHDCN920113), work in progress, and preliminary system testing.
During initial system testing numerous leaks (freon to cooling water) were identified in the heat exchangers for the ACU's.
The leaks were at the tube to tube sheet joint, which is a mechanical joint with the tubes pressure rolled into the tube sheets.
The licensee issued a
PER (BFPER940380)
to document the leakage and the vendor (Ellis and Watts)
was brought on site to assist in troubleshooting.
The licensee determined that the heat exchangers needed to be rebuilt utilizing a different design at the tube to tube sheet joint due to the higher pressure existing on the shell side (freon side) of the HX's.
The higher pressure design would incorporate a tube sheet with a groove cut into the hole where the tube is posi-tioned.
The tube is then rolled into the groove in the tube sheet providing a tighter seal for the high pressure side of the HX.
The vendor agreed to rebuild the HXs at their facility.
The licensee is currently removing the HXs for shipment to the vendor.
The inspectors reviewed and walked down the clearance associated with the removal of the Unit 3 HXs (Clearance No. 3-94-0432)
and found it to be adequate.
The licensee is reviewing the issues for reportability in accordance with 10 CFR Part 21.
This issue will be followed up by the inspectors when the HXs are returned from the vendor and testing on ACUs continues.
Unit 3 Restart Action Plan Preparations During this inspection period the residents and the regional Section Chief have conducted a detailed review of the open items with particular attention focused on Unit 3 items in preparation for restart.
The open items reviewed included the IFS list, THI Action Items, TI's, NRC Bulletins, Generic Letters, Unresolved Safety Issues, Generic Safety Issues, and Nulti Plant Actions Items.
This review was conducted to initiate a Unit 3 Restart Checklist as required by Manual Chapter 0350 to assign areas of responsibility for closure and coordinate the inspection effor ~'
Several minor discrepancies were identified which are currently being corrected.
Additionally, the inspectors held discussions with the licensee regarding the expected completion dates of specific major work activities such that NRC inspection of the activities can be planned appropriately.
No violations or Deviations were identified.
Containment Coatings (62700, 62702, 92702)
On August 1,
1994, a meeting was conducted between TVA and the NRC to discuss the licensee's containment coatings program.
Participants consisted of persons from TVA's Corporate Engineering and Licensing Organizations, licensee representatives from Watts Bar, Sequoyah, and Browns Ferry Nuclear Plants, and four NRC inspectors.
Matters of discussion encompassed an overview of the coatings program including the division of responsibility between the licensee's corporate and site organizations, the programmatic requirements and attributes of the coatings program, TVAs involvement with industry groups as they relate to coatings, and the site specific coatings programs for Watts Bar, Sequoyah, and Browns Ferry.
Representatives of the three sites present-ed the specific attributes of their containment coatings program including a discussion of the site specific implementing procedures, a
review of the major coatings utilized at the site, and an overview of previous audits, problems, and corrective actions performed for previ-ously identified problems.
Following the meeting, individual coatings inspections commenced at each of the TVA nuclear plants.
The following inspection conclusions are the result of the inspection effort at the Browns Ferry Nuclear Plant.
Browns Ferry's containment coatings program is under the purview of TVA General Engineering Specification G-55, Technical Requirements for Protective Coating Program for TVA Nuclear Plants.
This upper tier document specifies the engineering requirements for protective coating work in nuclear applications.
These requirements are implemented at the site by Modifications and Addition Instruction MAI-5.3, Protective Coatings.
This document further specifies the requirements for service level I coatings which are applied inside primary containment and are subject to a design basis accident.
Approved service level I coatings for the drywell are specified in Browns Ferry construction specification NIA-930.
These procedures were reviewed by the inspector.
During review of NlA-930, the inspector noted that Amerlock 400, a coating specified by TVA as a major coating utilized in the drywell, had a
specified maximum operating temperature of 180 degrees fahrenheit.
Because temperatures in the upper elevations of the drywell often exceed this value during power operations (a maximum of 198 degrees over the last three years),
the inspector questioned the operability of this coating.
The licensee investigated the inspector's concern and deter-mined that coating is acceptable for operation at continuous tempera-tures up to 200 degrees fahrenheit.
The inspector verified this by reviewing the vendors product data sheet.
The licensee informed the inspector that NlA-930 would be updated to reflect this informatio As a part of this inspection effort, the inspector walked down the Unit 3 drywell to examine the condition of the containment coatings.
Numerous areas within the Unit 3 drywell contained coatings with minor damage.
Additionally, the inspector reviewed the recently compiled Unit 3 uncontrolled containment coatings log.
The log, which is currently in draft format, states that approximately 4000 square feet of unqualified coating is installed in the Unit 3 primary containment.
This number will have to be reduced to a value less than 157 square feet prior to the restart of Unit 3.
The licensee is aware of this matter and is currently developing a methodology to attain this goal.
In addition, the licensee is currently assessing the condition of the Unit 3 torus coating following a recently (July, 1994)
completed walkdown.
Areas in need of repair were documented and are being evaluated.
Other than the SRV "T-guenchers",
no additional coated stainless steel surfaces were discovered.
These matters will be tracked as Inspector Followup Item 50-296/94-18-02:
Condition of Unit 3 Containment Coatings.
The inspectors will follow the licensee's progress in these matters and will ensure they are resolved prior to the restart of Unit 3.
During the walkdown of the Unit 3 drywell, the inspector selected a
sample of recently coated supports in order to verify that personnel performing the coating work were properly qualified in accordance with HAI-5.8, gualification of Journeyman Painters.
The supports selected were as follows;
- 3-47B465-465, Item ¹3
- 3-47B465-2050, Item ¹1 3-47B465-2050, Item ¹3 3-47B465-2050, Item ¹5 3-47B465-545, Item ¹8 3-47B465-545, Item ¹13
- 3-47B465-545, Item ¹15
- 3-47B465-2050, Item <<2
- 3-47B465-2050, Item ¹4
- 3-47B465-465, Item ¹4 3-47B465-545, Item ¹9 3-47B465-545, Item ¹14 In all cases, the licensee demonstrated that personnel applying service level I coatings to the above supports were properly qualified in accordance with HAI-5.8.
The inspector also reviewed the unqualified containment coatings log for Unit 2.
The log had been recently updated (June 10, 1994) to include unqualified coatings on the safety relief valve line "T-guenchers" discussed in IR 50-259,260,296/94-09.
The licensee has committed to remove this coating from the "T-guenchers" during the upcoming (October,
- 1994) Unit 2 outage.
Additionally, the inspector reviewed the licensee-
's calculations which determined the total allowable (157 square feet)
unqualified coatings inside primary containment.
These calculations contain conservative assumptions which include; During a design basis event, (LOCA) all unqualified coatings are assumed to flake off and form debris, and 2.
All flaked off material is assumed to be transported to the toru Based on the inspectors review of the calculations, the total allowable unqualified coatings is acceptable.
The final items reviewed during this inspection were independent inspection reports performed by S.G.
Pinney of the Browns Ferry containment coatings.
These audit reports were dated November 25, 1986, September 8,
1988, and March 26, 1991.
No additional concerns were noted.
The inspector concluded, through a review of the Browns Ferry Contain-ment Coatings program, that containment coatings are being properly controlled at Browns Ferry.
The inspectors will continue to monitor the licensee's program with future inspections on Units 2 and 3 and as stated above will ensure that all required actions related to Unit 3 containment coatings be completed prior to the restart of the unit.
One Inspector Followup Item was opened in the area of containment coatings.
Review of Open Items (92700)
(92901)
(92902)
(92903)
(92904)
a ~
b.
(CLOSED)
URI 296/84-29-01, Failure to Adequately Control Welding The inspectors researched this item and determined it was entered on the IFS list in error.
IR 84-29 was a security inspection which identified one violation, 84-29-01, Failure to Control Access to a Controlled Access Area, which was not related to the welding program.
This violation was subsequently closed for all three units in IR 85-49.
The inspectors also reviewed inspection reports from 1983 through 1991 to determine if the item was numbered incorrectly.
No items relative to this issue were identified.
In addition, the Region II DRS inspector whose name was assigned to this issue was contacted and he had no recollec-tion of this issue at this facility.
Based on the above discus-sion and numerous NRC inspections conducted in the welding area subsequent to 1984, this item is closed.
(CLOSED)
URI 259, 260, 296/94-07-01, Failure to Retain Overtime Waivers This issue, identified by the licensee, concerned approved over-time waivers not being retained according to site procedures.
Confusion existed as to who was responsible for ensuring that the documents were sent for microfilming as required by SSP-1.7, Overtime Restrictions (Regulatory).
As a result a number of waivers did not get microfilmed.
The licensee initiated BFPER940-071 to document the problem and identify corrective actions.
As a
result, SSP-1.7 was revised to assign the responsibility of distributing the approved waivers to the Site Vice President's secretary.
Based on this corrective action URI 259, 260, 296/94-07-01 may be close /
C, (CLOSED) IFI Item 259, 260, 296/92-30-03, Circuit Breaker Coordi-nation d.
e.
This issue concerns the spurious tripping of circuit breakers using solid state RHS-9 trip devices.
The licensee had previously replaced the old style EC trip devices with the newer RHS-9 trip
.device due to maintenance and parts availability.
See inspection reports 92-30, 93-14, 93-23, 93-44, 93-45, and 94-09 for addition-al details concerning this issue.
Due to the unreliability of the RHS-9 devices the licensee has a contract with the vendor to rebuild the breakers with RHS-9 trip devices and restore them to the original EC type devices until a suitable and proven solid state device is available.
The inspectors have followed this issue since identification and have reviewed the licensee's program to rebuild the breakers which is ongoing.
The inspectors consider this item closed.
(Closed)
IFI 50-259, 260, 296/92-39-01, Press Releases Did Not Adequately guantify the Offsite Radiological Release.
This issue was closed based on press release no.
3 that was provided during the exercise.
The press release provided an excellent description of the significance of the radiation inside the reactor building and its effect upon an employee working in the area.
The CECC staff had references in place to quantify a
radiological release to the offsite environs if one occurred.
(Closed)
IFI 50-259, 260, 296/93-41-01:
Review of Emergency Exercise Communications to Insure That "Drill Hessages" is Used.
This issue related to the failure of an environmental monitoring team to utilize "drill message" in reporting exercise offsite radiological measurements.
This issue is closed based on inspec-tors observations that "drill message" was properly used during this drill.
10.
Local Public Document Room Visit On July 14, 1994, two of the inspectors, accompanied by the NRR Project Hanager, visited the LPDR.
The facility is located within the public library in Athens, Alabama.
The inspectors noted that the facility was neat and organized such that material was easy to locate.
The inspec-tors were able to obtain and review a recently issued NRC inspection report without difficulty. Additionally, the inspectors located and reviewed an Information Notice involving the BWR core shroud issues which had recently been issued.
Equipment necessary to review the material operated properly.
The inspectors concluded that members of the public would be able to obtain and review documents, including those recently issued involving topics of interes Since the LPDR custodian was not available during the July 17, 1994, visit, a brief followup visit was conducted on August 2, 1994.
The inspector discussed the LPDR with the custodian.
It was verified that no problems had been encountered involving the LPDR and use had been minimal.
The custodian was provided the resident inspector office phone numbers.
Local Officials Meetings The senior resident inspector met briefly with local officials in order to introduce himself and describe the role of the NRC at Browns Ferry.
The inspector answered questions and provided phone numbers for future contacts.
Several officials were particular ly interested in the functions of the resident inspector office.
The status of the Unit 3 recovery and some emergency planning functions were also discussed.
The Region II DRP section chief attended one of the meetings.
Each of the resident inspectors participated in one of the other meetings.
The following is a list of the meetings and the officials contacted:
August
August
August 8 August
August
Dan Williams, Mayor of Athens Stanley Henefee, Limestone Co. Commissioner Barbara Coffey, Mayor of Moulton Larry Bennich, Morgan Co.
Commission Chairman Bill Dukes, Mayor of Decatur Floyd Shankle, Lawrence Co. Commissioner Joan Lang, Lawrence Co. Administrator Additionally, brief tours of two EOCs were conducted.
The Lawrence County EOC in Moulton and the Morgan County EOC in Decatur were visited.
At both facilities, the inspectors also met with the assigned TVA emergency planners.
Exit Interview (30703)
The inspection scope and findings were summarized on August 12, 1994 with those persons indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Item Number Status Descri tion and Reference
260/94-18-01 296/94-18-02 Opened and Closed Opened NCV-Inadequate Corrective Actions for Improper Drywell 0-ring Material, paragraph 6.
IFI-Condition of Unit 3 Con-tainment Coatings, Paragraph 8.
Licensee management was informed that 2 URIs and 3 IFIs were closed.
Acronyms and Initialisms ACU BFN BWR CECC CFR CR CRD DAD DCN DG dpm DRP DRS DW ECCS EECW EM EOC EP Eg F
FFTR FSAR GE GL HPCI HX IFI IFS
.IR LOCA LPDR NCV NOV NRC NRR OSC PEG PER Air Conditioning Unit Browns Ferry Nuclear Boiling Water Reactor Central Emergency Control Center Code of Federal Regulation Control Room Control Rod Drive Digital Alarming Dosimeter Design Change Notice Diesel Generator Disintegrations per Minute Division of Reactor Project Division of Reactor Safety Drywell Emergency Core Cooling System Emergency Equipment Cooling Water Electrical Maintenance Emergency Operations Center Emergency Preparedness Environmental gualification Fahrenheit Final Feedwater Temperature Reduction Final Safety Analysis Review General Electric Company Generic Letter High Pressure Coolant Injection Heat Exchanger Inspector Followup Item Inspection Followup System Inspection Report Loss of Coolant Accident Local Public Document Room Non-Cited Violation Notice of Violation Nuclear Regulatory Commission Nuclear Reactor Regulation Operations Support Center Procurement Engineering Group Problem Evaluation Report
PMT PSS gA gC RAR RCA RCI RCSS RCW REX RFP RHR RHRSW SE SI SRV SSP TI TID TMI TOE TS TSC TVA URI UT VDC WO
Post Maintenance Test Power Service Shop guality Assurance guality Control Radiological Awareness Report Radiological Controlled Area Radiological Control Instruction Radiological Control Shift Supervisor Raw Cooling Water Radiation Exposure System Reactor Feed Pump Residual Heat Removal Residual Heat Removal Service Water Safety Evaluation Surveillance Instruction Safety Relief Valve Site Standard Practice Technical Instruction/Temporary Instruc-tion Total Integrated Dose Three Mile Island Technical Operability Evaluation Technical Specifications Tech Support Center Tennessee Valley Authority Unresolved Item Ultrasonic Testing Volts Direct Current Work Order
r