IR 05000397/1988021
| ML17284A509 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 08/24/1988 |
| From: | Bosted C, Crews J, Johnson P, Sorensen R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17284A507 | List: |
| References | |
| 50-397-88-21, NUDOCS 8809140215 | |
| Download: ML17284A509 (18) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION REGION V
Report No:
Docket No:
50-397/88-21 50-397 Licensee:
Inspection at:
WNP-2 Site near Richland, Washington Inspection Conducted:
May 20 - July 7, 1988 Washington Public Power Supply System P. 0.
Box 968 Richland; WA 99352 Facility Name:
Washington Nuclear Project No.
(WNP-2)
Inspector:
Inspector:
Inspector:
Approved by:
R.
J L
oste
,
endor esident Inspector So s n, Resident Inspector r w, Sen or Reactor Engineer a
e
>gne te sgned g ~KS8 ate Soigne
~Summa r:
. Jo nson, C ief Reactor Projects Section
e sgne Ins ection on Ma'0 - Jul 7,
1988 50-397/88-21 A~Id:
R I
d I
by I
Id room operations, engineered safety feature (ESF) status, surveillance program, maintenance program, licensee event reports, special inspection topics, and licensee action on previous inspection findings.
During this inspection, Inspection Procedures 30703, 35701, 61726, 62703, 71707, 71709, 71710, 71881, 90712, 90713, 92700, 92701, 92702, and 92703 were covered.
Results:
Two violations of NRC requirements were identified:
(1) the TTec Tncal Specification 3.4.6.1 heatup limit of 100'F mas exceeded (see paragraph 13).
(2)
A licensee event report (LER) was not submitted within 30 days of discovery that heatup and cooldown limits were exceeded on two occasions during 1987 (see paragraph 13).
A weakness was observed pertaining to inadequate corrective action taken in response to previous gA audit findings associated with plant heatup/cooldown rates.
This observation indicated shortcomings on the part of operations and gA personnel alike., in that the audit finding resolution process did not ensure that the corrective actions taken were sufficient to preclude occurrence.
8809140215 880824 PDR ADOCK 05000397
PNU
DETAILS Persons Contacted L. Oxsen, Assistant Managing Director for Operations D. Bouchey, Director, Licensing and Assurance
- C. Powers, Plant Nanager
- J. Baker, Assistant Plant Manager
- K. Cowan, Technical Manager
- D. Feldman, Plant guality Assurance Manager
- R. Graybeal, Health Physics and Chemistry Manager J.
Harmon, Maintenance Manager
- S. McKay, Operations Manager
- J. Peters, Administrative Manager
"A. Hosier, Licensing Manager
- R. Koenigs, Assistant Technical Manager W. Shaeffer, Assistant Operations Manager J. Allen, Assistant Health Physi,cs Super visor B. Twitty, Principal Engineer, Events Assessment Staff The inspectors also interviewed various control room operators, shift supervisors and shift managers; and, engineering, quality assurance, and management personnel relative to activities in progress.
- Attended the Exit Meeting on July 7, 1988.
Plant Status At the start.of the inspection period, the plant was in an annual refueling outage.
The reactor internals were reinstalled June 4, 5, and 6.
The newly installed reactor water cleanup (RWCU) pump "A" was started on June 10 for normal usage.
Shortly after the pump was started, it failed due to sheared bolts on the thrust bearing assembly.
On June 13, while doing surveillances on the drywell spray isolation valves, the outboard containment isolation valve RHR-V-16A operator failed and would not operate from the control room.
The valve position indication lights showed that the valve was closed.
The downstream valve inside containment, RHR-V-17A, was then cycled in an attempt to clear an interlock which was thought to be the cause of V-16A not working.'ater, V-16A was found to be open between 1/2 to 1 inch and when V-17A was opened about 50-75 gallons of water were drained from the drywell spray piping into the drywell.
Contamination levels in some locations of the drywell measured 500,000 cpm.
During the outage, the licensee identified prob'lems with and replaced a
number of safety related motor operated valve operator torque switches.
Failures in 16 torque switches identified from Motor Operated Valve Actuator Testing System (MOVATS) testing and valve operator inspection were precursors to this switch changeout (see paragraph 12 for further details).
The outage ended on June 19 when the plant was taken critical at 5:25 a.m.
Pressure was raised to 400 psig for surveillance tests on the main steam isol'ation valve (MSIV) position indication limit switches.
Failure of this surveillance led to replacement of three switches.
Following position switch surveillances, the MSIVs were cycled for an additi,onal
.
functional test.
MSIV 28A failed to reopen, after being cycled closed.
The valve was deactivated and the heatup continued to 1000 psig on June 23.
The turbine was placed in operation at 20% power on June 24 to test the turbine throttle valves and check the plant for steam leaks.
The reactor was shut down on. June 25 to accomplish repairs on NSIV 28A.
The
valve operator was found to be the source of the valve operation problem.
The hydraulic dashpot was locked up, which prevented the valve from operating correctly.
After the dashpot was replaced, the reactor was restarted on June 27.
During the ensuing heatup the operators determined that the Technical Specification limit of 100'F heatup in a one-hour period had been exceeded.
The heatup was stopped and an engineering evaluation was performed before the heatup was continued (see paragraph 13 for additional information).
The generator was placed in service on June
and power was raised to 94Ã.
Vibration problems with main turbine governor valves 1 and 4, similar to those before the refueling outage, were again experienced.
Pressure and power oscillations occurred on July 1 and 2 due to main turbine governor valve t3 being in test to minimize the governor valve vibration.
The turbine valve control system (digital electro-hydraulic or DEH) reached a limit on the maximum control signal and limited the control signal controlling the amount of steam to the main turbine and bypass valves causing system pressure and reactor power to increase.
After the DEH was recalibrated to allow the number
governor valve to be closed, the DEH controlled the system pressure normally.
Operation with number 3 governor valve shut has minimized vibration from that previously experienced.
Reactor power was subsequently increased to 1004, and remained there for the duration of the report period.
Previousl Identified NRC Ins ection Items 92701 92702 The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
a.
0 en Enforcement Item 397/87-19-12
Diesel Generator Fuel u
ot sn ccor ance
)t ec naca ecs icatsons The licensee's followup action for this item was expected to be completed by 'July 20, 1988 and will be followed up at that time.
This item will remain open pending additional licensee actions.
b.
Closed Enforcement Item 397/87-19-22
Failure to Im lement erma ver oa roce ures Contrary to the requirements of Technical Specification 6.8.3, changes were improperly'made to surveillance procedures which tested MOV thermal overloads.
This occurred when maintenance personnel noted that installed thermal overload devices did not match the size
specified in the procedure and revised the test currents in the comments section of the procedure.
The licensee responded to this violation by reviewing surveillance test data to ensure that overload relays would not prematurely trip. Also, surveillance procedures that test thermal overloads were revised to include the correct overload heater size, test current, and minimum trip time.,
Finally, all electric shop personnel were counselled on the proper method of obtaining procedure changes.
The inspector verified the licensee's latter two actions.
This item is closed.
Closed)
Enforcement Item (397/87-19-24
Failure to Provide nstructions or erio ic estin an a i ration o ime e
a
~ea s
Contrary to the requirements of section 6.8.1.a of the Technical Specifications, the licensee had failed to establish a procedure for the periodic calibration of numerous safety related time delay relays (TDRs).
The licensee therefore added 159 different safety related and non safety related TDRs to the Scheduled Maintenance System (SNS) program.
Approximately 100 additional TDRs were later identified for addition into the SNS data base.
The inspector verified that TDRs were either entered, or in the process of being entered, into the SMS.
Some TDRs were assigned a calibration frequency of four years; however, most were placed on a two year frequency.
The inspector reviewed a small sample of data sheets for completed TDR calibrations and noted that a required value for the relay's time delay was included for the calibration check, but no tolerance or acceptable range of values was included.
The licensee representative stated that this problem had already been identified and was in the process of being corrected.
The inspector will verify this as part of future routine inspection effort.
This item is closed.
(0 en)
Followu Item 87-19-11:
Nitro en Tank Potential Threat o
iese enerators A concern was generated that addressed a potential problem in the event that the liquid nitrogen tank would fall during a seismic event or tornado.
It was postulated that the tank could rupture and the escaping nitrogen could suffocate the operating diesel generators.
The engineering analysis had not been completed at the time of the inspector's review of this item.
The licensee expects to have this work completed by August 1, 1988.
This item will remain open pending the completion of the analysi f.
(Closed). Enforcement Item 87-19-30
- Failure to Follow Housekee in an eismic roce ures (Closed Unresolved Item (87-26-34
- Housekee in Closed Followu Item 87-32-01):
Housekee in The Notice of Violation, the Unresolved Item, and the Followup Item all addressed housekeeping practices.
The plant housekeeping procedure 10.2.53 was revised June 23, 1988 to address these concerns.
Routine inspections during the inspection period recognized improvements with housekeeping.
These items are closed.
g.
(0 en) Followu Item 87-19-25:
No Procedure Coverin Seismic ontro o
i tin ui ment The maintenance department was planning to issue a procedure to address this concern by August 1, 1988.
This item will remain open awaiting completion of the licensee's actions.
4.
0 erational Safet Verification 71707)
a.
Plant Tours
.
The following plant areas were toured by the inspectors during the
'course of the inspection:
Reactor Building Control Room Diesel Generator Building Radwaste Building Service Water Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
=
The following items were observed during the tours:
(1)
0 eratin Lo s and Records.
Records were reviewed against ec nica peci ication and administrative control procedure requirements.
(2) Monitorin Instrumentation.
Process instruments were o serve or corre ation etween channels and for conformance with Technical Specification requirements.
(3) Shift Mannin
.
Control room and shift manning were o serve or conformance with 10 CFR 50.54.(k), Technical Specifications, and administrative procedure (4)
E ui ment Lineu s.
Valves and electrical breakers were veri ie to e in the position or condition required by Technical Specifications and Administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
On June 16, 1988, during a tour in the cable riser room between the reactor building and the radwaste building, the inspector identified a temporary non-class lighting cord that was routed inside Class 1E cable tray, P-Div 2-6926.
At grade level, the lighting cord was attached outside the vertically oriented cable tray, but approximately 10 feet above grade, the cable tray ran horizontal and the temporary lighting cord was routed inside the cable tray.
This was identified to licensee management and actions were taken to prevent recurrence.
(5)
E ui ment Ta in
.
Selected equipment, for which tagging requests a
een initiated, was observed to verify that tags were in place and the equipment was in the condition specified.
(6) General Plant E ui ment Conditions.
Plant equipment was observed for indications of system leakage, improper lubrication, or other conditions that would prevent the system from fulfillingits functional requirements.
(7) Fire Protection.
Fire fighting equipment and controls f
ihT hi 1Ep if'
d administrative procedures.
(8) Plant Chemistr
.
Chemical analyses and trend results were reviewe or conformance with Technical Specifications and administrative control procedures.
(9) Radiation Protection Controls.
Activities observed are iscusse in paragr ap ( 10) Plant Housekee in
.
Plant conditions and material/equipment storage were o served to determine the general state of cleanliness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
(11) ~Securit
.
Activities observed are discussed in paragraph 9.
No violations of NRC requirements were identified.
5.
En ineered Safet Feature S stem Walkdown 71707 71710 Selected engineered safety feature systems (and systems important to safety)
were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
The inspectors also verified that system valves were in the required position and locked
as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operable.
Accessible portions of the following systems were walked down on the
. indicated date.
~Ss tern Diesel Generator Systems, Divisions 1, 2, and
Hydrogen Recombiners Low Pressure Coolant Injection (LPCI)
Trains "A", "8", and
"C" Low Pressure Core Spray (LPCS)
High Pressure Core Spray (HPCS)
Reactor Core Isolation Cooling (RCIC)
Residual Heat Removal (RHR), Trains IIA II a n d II8 II Scram Discharge Volume System Standby Liquid Control (SLC) System 125V DC Electrical Distribution, Divisions 1 and
Date June
June
June 20,
May 23, June 2, June 14, 20,
June
June 8,
May 24, 31, June 14,17 June
June
June
250V DC Electrical Distribution June
No violations of NRC requirements or deviations were identified.
6.
Surveillance Testin 61726 a
~
b.
Surveillance tests required to be performed by the Technical Specifications (TS) were reviewed on a sampling basis to verify that:
(1) the surveillance tests were correctly included on the facility schedule; (2)
a technically adequate procedure existed for performance of the surveillance tests; (3) the surveillance tests had been performed at the frequency specified in the TS; and (4)
test results satisfied acceptance criteria or were properly dispositioned.
Portions of the following surveillances were observed by the inspectors on the dates shown:
Procedure Descri tion Dates Performed 7.4.8.2.1.17 7.4.5.1.9 7.4.3.2.1.69 18 Month Battery Test,B1-2 RHR "B".Operability RHR Shutdown Cooling Mode Permissive Channel Functional Check June
June
June
7.4.1.4.1.1 7.4.1.4.1.2 7.4.1.1.
7.0.0 Rod Worth Minimizer Precritical Check Rod Worth Minimizer Operability Prior to Shutdown Shutdown Margin Shift and Daily Instrument Checks June
June
June
June
No violations of NRC requirements or deviations were identified.
7.
Plant Maintenance 62703 During the inspection period, the inspectors observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements, compliance with administrative and maintenance procedures, required gA/gC involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspectors verified reportability for these activities was correct.
The inspectors witnessed portions of the following maintenance activities:
Descri tion Date Performed Installation of TIP tubing per AT 3690 June
Troubleshooting of the radwaste ventilation system per AT 4388 Reinstallation of Condenser Booster Pump 2A motor per AT 3763 June
June
No violations of NRC requirements or deviations were identified.
8.
Radiolo ical Protection Practices 71709 The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
Areas observed included control point
operation, records of licensee's surveys and postings of. radiation and high radiation and contamination areas within the radiological controlled area.
The inspectors also observed compliance with Radiation Exposure Permits, proper wearing of personnel monitoring devices, and personnel frisking practices.'he inspectors verified that health physics supervisors and professionals conducted frequent plant tours to observe activities in progress and were generally aware of significant plant activities, particularly those related to radiological conditions and/or challenges.
,ALARA consideration was given to maintenance activities observed by the inspector.
No violations of NRC requirements or deviations were identified.
9.
Ph sical Securit 71881)
The inspectors periodically observed security, practices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures.
The inspectors observed that the number of guards was adequate for the requirements of the security plan; that the search equipment at the access control points was operational; that the protected area barriers were well maintained without breaks; and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functional.
Night illumination inside the protected area was observed and obstructions were lighted adequately.
Surveillance equipment was also observed during this inspection.
No violations of NRC requirements or deviations were identified.
10.
Licensee Event Re ort L'ER Followu 90712, 92700 a.
The following LERs associated with operating events were reviewed by the inspectors.
Based on the information provided in the report it was concluded that reporting requirements had been met, root causes had been identified,'nd corrective actions were appropriate.
The below LERs are considered closed.
LER NUMBER DESCRIPTION LER 87-25-00 ESF Isolation Caused by Reactor Protection System LER 87-25-01 (RPS)
Equipment Halfunction LER 87-28 Spurious Containment Isolation Caused by Temperature Monitoring Components LER 87-32 Technical Specification Violation Due to RCIC Isolation Trip System Inoperability LER 87-14 ESF Actuation Due to Equipment Malfunction b.
The following LERS were followed during the time of occurrence and the corrective actions were verified. These items'are closed.
LER 88-02 RCIC Isolation Valve Design Outside Design Requirements
LER 88-03 LER 88-05 LER 88-07 Reactor Scram Caused by Personnel Error Control Room Emergency Filtration System Train
'B'ypass Not in Compliance with Technical Specifications Reactor Building Roof Rupture c.
The corrective actions for the below listed LERS were not complete at the time of the inspection.
In these cases the training for personnel had not been completed and documented.
LER 87-31-00 is closed; LER 87-31-01 will remain open pending completion of the technician training discussed in the LER.
LER 87-31-00 250 Volt Battery Float Voltage Below Limits LER 87-31-01 d.
LER 88-06:
Low Reactor Vessel Level RPS Actuation due to Inade uate rocedure.
This LER was submitted following a situation in which a drain path from the reactor to the main condenser was inadvertently established.
Complicating this event, operators were attempting to reestablish feedwater flow to the reactor using the condensate booster pumps.
The main turbine bypass valves were used to reduce reactor pressure and allow the booster pumps to supply water to the reactor vessel.
Due to the magnitude of the pressure changes in the reactor pressure vessel (RPV), the RPV level also experienced large changes.
These level changes prevented the operator from detecting a loss of RPV water inventory of approximately 2400 gallons.
The LER addressed the event adequately, but did not acknowledge that the operators were unaware of the loss of reactor coolant or that the large and rapid changes in RPV pressure were inappropriate'for the plant conditions.
Once the reactor - main condenser flow path was identified, only administrative controls were established to control other similar drain paths.
The use of administrative controls have not been successful in the past.
The licensee committed to resubmit this LER and address these concerns.
This LER will remain open pending resubmission.
No violations of NRC requirements or deviations were identified.
11.
Review of Periodic and S ecial Re orts 90713 Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9.1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report contained the information required to be reported by NRC requirements; test results and/or supporting information were consistent with design predictions and performance specifications; and the validity of the reported information.
Within the scope of the above, the 'following report was reviewed by the inspector.
Monthly Operating Report for May 1988.
No violations of NRC requirements or deviations were identified.
'otor 0 crated Valve 0 erators 92701)
During the annual refueling outage, valve actuator testing was scheduled for 21 motor operators that had not been tested before and seven previously tested operators.
A total of 16.operators of the "Limitorque" types SMB-000 and SMB-00 had been tested (nine untested and seven previously tested)
when several concerns were identified that had generic implications.
The concerns were classified into three categories; torque switches, change in grease consistency, and apparently undersized spring packs.
The torque switch concerns were a combination of two problems.
The first problem, and the most numerous with, ll examples, was identified as
"melamine shrinkage".
The material used in the construction of the switch, "melamine" by trade name, underwent a material densification which caused the switch to shrink around the shaft of the switch, raising the force needed to operate the switch.
The cause for 'the shrinkage had not yet been identified, but was thought to be due to heat and radiation.
The second problem, identified in six cases, was broken actuator tabs on the torque switches.
These tabs are operated by the torque shaft and operate the switch, and when the tabs are broken the switch cannot function.
The cause of the tab breakage and the time of occurrence was not known.
The grease used in the operators,
"Exxon Nubula", is normally a free flowing high temperature, high radiation type grease.
During the inspection, the grease was found to have changed to a hard consistency.
The cause of the change in the grease material properties was yet to be determined, but was believed by,,the licensee to be due to long exposures to high temperatures.
Twenty seven motor operators in the steam tunnel, drywell, and reactor building were inspected, and degraded grease was found in 15 motor operators.
All the samples that were degraded were located in the steam tunnel and drywell and all were in type SMB-000 motor operators.
The licensee concluded that the grease hardening condition may shorten the lifetime of the" operator, but did not render any of these valves inoperable.
The licensee.also inspected the gears in these operators and found no significant wear.
The degraded grease was removed from accessible areas, and new grease was added.
The spring pack concerns were later identified as being due to a lack of understanding of the design parameters, rather than a material problem.
Test personnel were concerned that the thrust values obtained by the testing was less than the test device manufacturer recommended for that size valve.
The licensee determined that the thrust values supplied by the
"MOVATS" company were very conservative (approximately 300K of the required thrust for worst case differential pressure across the valve).
A final analysis by engineering determined that the previous spring packs were acceptabl Corrective actions were taken by the licensee to change the torque switches in all SMB-00 and SMB-000 motor operators.
The replacement switches used a Limitorque recommended
"Fibrite" material (in place of melamine) with metal tabs.
Plant Heatu 92703)
On June 27, during heatup of the plant, the heatup limitation of Technical Specification 3.4.6.1 was exceeded.
The operators were at a
point in the heatup (212'F)
where a transition was made in the instrument being used to track the heatup rate.
Although the heatup to this point had been tracked using the temperature recorders, a change was made to use the saturation temperature corresponding to the digital reactor pressure indicator.
At this time, one operator selected a "goal" pressure for the operator at the reactor controls to control the reactor so that a heatup rate of 100'F would not be exceeded.
The selected goal pressure was 50 psig.
This was later determined to be excessive, although the reactor operator had thought that 60 psig was the specified pressure value.
The reactor operator stopped the reactor power increase when system pressure was at 50 psig and let the reactor pressure
"coast" into 60 psig.
The actual pressure rise stoppe'd at approximately 61 psig, which corresponded to a calculated 137'F temperature increase for the one hour period.
This was identified by the operators performing the heatup and the heatup was stopped while an engineering evaluation was performed.
The technical evaluation of the event by the engineering department concluded that no safety concerns were created by the excessive heatup rate.
Following this event, members of the management staff conducted a
review of the circumstances which proceeded this occurrence.
The management review and the conduct of a "Peer Review Group" evaluated the root cause of the event as human error, primarily due to poor communications.
The inspector determined that the plant gA organization had performed a
surveillance in March and April 1988 which identified that Operations performed several heatups and cooldowns at or near the 100 degree limit during 1987.
Upon closer examination, gA found that some Technical Specifications limits had apparently been exceeded.
Both operations and technical staff members reviewed the gA Surveillance Report and revised the plant procedures to.control pressure changes with the digital hydraulic control system.
However, no additional guidance was 'provided to the operators for manual control of heatups and cooldowns or for temperatures below 212'F.
In addition, no action was taken to require more conservative monitoring (e.g.,
more often than every half-hour) of heatups and cooldowns or to specify a target heatup/cooldown rate less than the 100'F/hr allowed by. the Technical Specifications.
The NRC Enforcement Policy (10 CFR Part 2, Appendix C, Section V.G)
states that the NRC will not normally issue a Notice of Violation for violations which are identified by the licensee and which meet certain other criteria.
One of these criteria is that "It was not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation."
Although the excessive heatup rate on June 27, 1988 was identified by licensee personnel, it could have been prevented by more effective licensee
actions in response to the gA surveillance discussed above.
It is therefore cited in the Notice of Violation which accompanies this inspection report.
(Enforcement Item 88-21-01).
A plant problem report was not generated to document the previously identified Technical Specification limit violation, and an LER was not submitted to the NRC within 30 days after the problem was identified.
This was identified as a violation of the licensee event reporting requirements of 10 CFR 50.73 (Enforcement Item 88-21-02).
Two violations of NRC requirements were identified.
Develo ment and Im lementation of Root Cause Pro ram 35701)
Discussions were held with licensee management regarding actions to develop and implement a root cause program applicable to WNP-2.
These discussions established the following.
Three positions had been authorized in a newly established Event Assessment Staff within the licensee's department of Licensing and Assurance.
Recruiting efforts to fill these positions were in progress, with one individual selected as of June 27, 1988.
Initial efforts to determine the role of the dedicated Event Assessment Staff as well as selected plant staff in an integrated root cause program were in progress at the time of the inspection.
These efforts included the training of personnel, the development and/or revision of applicable procedures, and the development of criteria defining the threshold for events requiring root cause determination.
During meetings with senior licensee management (corporate, plant and Licensing and Assurance)
on June 28, 1988, licensee management committed to establish an Action Plan covering development and implementation of a root cause program, including scheduled milestone dates, by August 1, 1988.
No violations or deviations were identified.
Review of Re orts of Radiolo ical Occurrence RROs 35701 Eleven recently completed RROs were selected at random and examined for root cause determination.
The plant procedure governing RROs, Plant Procedure Manual (PPM) No.
11.2.19.1, states with regard to description of.the occurrence (including principal causes),
"Describe the occurrence.... If possible, indicate whether the occurrence was caused by personnel error or negligence,'aulty or inadequate design of equipment or lack of appropriate methods or 'procedures."
Of the RROs examined it was observed by the inspector that the reports in most instances included descr iptions (often brief) of the occurrence,
'ith little discussion of cause or causes.
Root cause, as such, was not addressed in the procedur The inspector did observe that six of the RROs involved personnel or personnel clothing contamination.
In these instances Personnel Contamination or Personnel Clothing Contamination Reports had been prepared in accordance with applicable plant procedures.
The plant procedures covering these reports had either been initially issued (in the case of personnel clothing contamination)
or revised (in the case of personnel contamination),on January 6, 1988.
Both procedures required that a critique, including root cause(s)
be documented in the report.
An examination of the reports of personnel and/or personnel clothing contamination revealed that in five of six reports root cause of the occurrence was addressed.'n one instance, however (Report No. 2-88-064, dated May 26, 1988), the CRITI UE:ROOTCAUSES section of the repor t
.
contained only the follow>ng statement, Worker informed not to touch face or bare skin while undressing."
Discussions were held with the Assistant Health Physics (HP) Supervisor regarding consistency of root cause determination in the case of reports of personnel or clothing contamination.
This discussion revealed that HP supervision had recognized a need to improve the consistency of root cause documentation.
As a result, guidelines had been prepared for use during the critique of contamination occurrences, including interview with the person or persons directly involved.
This guidance, entitled Standard Contamination Root Causes, provided categories, with examples, for each of the potenti~a root causes.
Plant HP supervision expressed the view that use of the guidelines would better ensure consistent and more complete root cause documentation for such occurrences.
No violations or deviations were identified.
Exit Meetin 30703 The inspectors met with licensee management representatives periodically during the report period to discuss inspection status and an exit meeting was conducted with the indicated personnel on July 7, 1988.
The scope of the inspection and the inspector's findings, as noted in this report, were discussed and acknowledged by the licensee re-presentatives.
Licensee personnel did not identify as proprietary any of the materials reviewed or discussed during the inspection.